Berkshire Hathaway Energy
2017 Fixed-Income Investor Conference
A Berkshire Hathaway Company
Forward-Looking Statements
This presentation contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking
statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate,"
"continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon Berkshire Hathaway Energy Company (“BHE”) and its
subsidiaries, PacifiCorp and its subsidiaries, MidAmerican Funding, LLC and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its
subsidiaries or Sierra Pacific Power Company and its subsidiaries (collectively, the “Registrants”), as applicable, current intentions, assumptions, expectations
and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of each Registrant and could cause
actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:
– general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including income tax
reform, initiatives regarding deregulation and restructuring of the utility industry, and reliability and safety standards, affecting the respective
Registrant's operations or related industries;
– changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and
capital costs, reduce facility output, accelerate facility retirements or delay facility construction or acquisition;
– the outcome of regulatory rate reviews and other proceedings conducted by regulatory agencies or other governmental and legal bodies and the
respective Registrant's ability to recover costs through rates in a timely manner;
– changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation,
energy efficiency and private generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply
or the respective Registrant's ability to obtain long-term contracts with customers and suppliers;
– performance, availability and ongoing operation of the respective Registrant's facilities, including facilities not operated by the Registrants, due to
the impacts of market conditions, outages and repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and
operating conditions;
– the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the control of each respective Registrant or by a
breakdown or failure of the Registrants' operating assets, including storms, floods, fires, earthquakes, explosions, landslides, mining accidents,
litigation, wars, terrorism, embargoes, cyber security attacks, data security breaches, disruptions or other malicious acts;
– a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of
balancing its generation resources with its retail load obligations;
– changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a
significant impact on generating capacity and energy costs;
– the financial condition and creditworthiness of the respective Registrant's significant customers and suppliers;
– changes in business strategy or development plans;
– availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other
sources of debt financing and volatility in the London Interbank Offered Rate, the base interest rate for the Registrants' credit facilities;
– changes in the respective Registrant's credit ratings;
– risks relating to nuclear generation, including unique operational, closure and decommissioning risks;
Forward-Looking Statements
– hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;
– the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and
changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;
– the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;
– fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;
– increases in employee healthcare costs;
– the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and
other postretirement benefits expense and funding requirements;
– changes in the residential real estate brokerage and mortgage industries and regulations that could affect brokerage and mortgage transactions;
– unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors
that could affect future facilities and infrastructure additions;
– the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;
– the impact of new accounting guidance or changes in current accounting estimates and assumptions on the consolidated financial results of the
respective Registrants;
– the ability to successfully integrate future acquired operations into a Registrant's business; and
– other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the United States Securities and
Exchange Commission (“SEC”) or in other publicly disseminated written documents.
Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants‟ filings with the SEC. Each Registrant
undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The
foregoing factors should not be construed as exclusive.
This presentation includes certain non-Generally Accepted Accounting Principles (“GAAP”) financial measures as defined by the SEC‟s Regulation G. Refer to
the BHE Appendix in this presentation for a reconciliation of those non-GAAP financial measures to the most directly comparable GAAP measures.
Pat Goodman
Executive Vice President and Chief Financial Officer
Berkshire Hathaway Energy
2017 Fixed-Income Investor Conference
Energy Assets
(1) Includes both electric and natural gas
customers and end-users worldwide.
Additionally, AltaLink serves
approximately 85% of Alberta, Canada’s
population
(2) Net MW owned in operation and under
construction as of December 31, 2016
Assets $85 billion
Revenues $17.4 billion
Customers(1) 8.6 million
Employees 21,000
Transmission Line 33,500
Miles
Natural Gas Pipeline 16,400
Miles
Generation Capacity 31,599 MW(2)
Renewables 35%
Natural Gas 33%
Coal 30%
Nuclear and Other 2%
Berkshire Hathaway Energy
Vision
To be the best energy company in serving our customers, while delivering sustainable energy solutions
Culture
Personal responsibility to our customers
Strategy
Reinvest in our businesses
• Continue to invest in our employees and
operations, maintenance and capital
programs for property, plant and equipment
• Position our regulated assets to manage
bypass risk by providing excellent service
and competitive rates to our customers
• Decarbonize our operations by participating
in energy policy development, transforming
our businesses and assets
• Advance cybersecurity and physical security
programs
Invest in internal growth
• Pursue the development of a value-enhancing
energy grid and gas pipeline infrastructure
• Create customer solutions through innovative
rate design and redesign
• Grow our portfolio of renewable energy
• Develop strong cybersecurity and physical
resilience programs
Acquire companies
• Additive to business model
Competitive Advantage
Berkshire Hathaway Ownership
BHE Competitive Advantage
• Diversified portfolio of regulated assets
– Weather, customer, regulatory, generation, economic and catastrophic
risk diversity
• Berkshire Hathaway ownership
– Access to capital from Berkshire Hathaway allows us to take advantage
of market opportunities
– Berkshire Hathaway is a long-term owner of assets which promotes
stability and helps make BHE the buyer of choice in many circumstances
– Tax appetite of Berkshire Hathaway has allowed us to receive significant
cash tax benefits from our parent of $1.1 billion and $1.8 billion in 2016
and 2015, respectively
• No dividend requirement
– Cash flow is retained in the business and used to help fund growth and
strengthen our balance sheet
Diversity in Our Portfolio
(1) Calculated using reported shares outstanding on each respective balance sheet for the period ending December 31, 2016, per S&P Capital IQ
(2) As reported by company public filings
Comparable Companies
($ billions)
Market Cap
Dec. 31, 2016(1)
Net Income
Dec. 31, 2016(2)
NextEra Energy Inc. $55.9 $2.9
Duke Energy $54.3 $2.2
Southern Company $48.7 $2.4
Dominion Resources $48.1 $2.1
Exelon Corp. $32.8 $1.1
DISTRIBUTION
Berkshire Hathaway Energy‟s integrated utilities operate in 11 states and serve
approximately 4.7 million customers; Northern Powergrid has 3.9 million end-users, making
it the third-largest distribution company in Great Britain
TRANSMISSION
We own significant transmission infrastructure in 15 states and the province of Alberta; with
our assets at PacifiCorp, NV Energy and AltaLink, we are the largest transmission owner in
the Western Interconnection
PIPELINES
BHE Pipeline Group transported approximately 8% of the total natural gas consumed in the
United States during 2016
GENERATION
We own approximately 31,600 MW of generation in operation and under construction, with
resource diversity ranging from natural gas and coal to renewable sources
RENEWABLES
As of December 31, 2016, we had invested $19 billion in solar, wind, geothermal and
biomass generation
Berkshire Hathaway Energy
2016 Net Income: $2.5 billion
Revenue and EBITDA Diversification
(1) Excludes HomeServices and equity income, which add further diversification
(2) Refer to the BHE Appendix for the calculation of EBITDA; percentages exclude Corporate/other
• Diversified revenue sources reduce regulatory concentrations
• In 2016, approximately 88% of EBITDA was from investment-grade regulated
subsidiaries
BHE 2016
Energy Revenue(1): $15 Billion
PacifiCorp
31%
NV Energy
17% MidAmerican
Funding
15%
Northern
Powergrid
9%
BHE Pipeline
Group
9%
BHE
Renewables
8%
BHE
Transmission
7%
HomeServices
4%
BHE 2016
EBITDA(2): $7 Billion
Nevada
20%
Utah
16%
Iowa
16%
Oregon
9%
Wyoming
6%
Illinois
4%
California
4%
Washington
2%
Idaho
2%
FERC
7%
United
Kingdom
7%
Alberta
3%
Other
4%
BHE Asset Profile
82%
8%
10%
Renewables and Other
Natural Gas Generation
Coal Generation
Berkshire Hathaway Energy
Net Property, Plant and Equipment as of December 31, 2016
• Berkshire Hathaway Energy is growing its renewable energy portfolio and continues to de-risk its
balance sheet as it relates to carbon based generation assets. We are leading the way to a
sustainable energy future for our customers
84%
2%
14%
MidAmerican Energy PacifiCorp
69%
9%
22%
64%
33%
3%
Nevada Power
74%
19%
7%
Sierra Pacific Power
Generation Diversification
2016 BHE Power Capacity – 31,599 MW
2016 BHE Power Generation – 113 TWh
Total
Renewables
35%
Total
Renewables(1)
24%
(1) All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply
with RPS or other regulatory requirements, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from
energy purchased
Coal
30%
Natural Gas
33%
Nuclear and
other
2%
Wind
26%
Solar
4%
Hydro
4%
Geothermal
1%
Coal
46%
Natural Gas
26%
Nuclear and
other
4%
Wind
15%
Solar
3%
Hydro
4%
Geothermal
2%
Coal
58%
Gas
23%
Nuclear and
Other
3%
Wind
5%
Hydro
8%
Geothermal
3%
Total
Renewables
16%
Total
Renewables(1)
12%
Coal
74%
Gas
9%
Nuclear and
Other
5%
Wind
2%
Hydro
5%
Geothermal
5%
2006 BHE Power Capacity – 16,386 MW
2006 BHE Power Generation – 83 TWh
Wind and Solar Investments
• In August 2016, the IUB approved MidAmerican Energy‟s request to construct up to 2,000 MW of additional
wind-powered generating facilities which are expected to be placed in-service in 2017 through 2019, with a
cost cap of $3.6 billion
• BHE Solar acquired the 110 MW Alamo 6 solar project in Texas in January 2017 for approximately $385
million, and is expected to spend approximately $218 million constructing the community solar gardens in
Minnesota, which are comprised of 28 locations with a capacity of 95 MW
• In 2016, PacifiCorp, MidAmerican Energy and BHE Renewables purchased $324 million of equipment that in
the future will facilitate the repowering of at least 1,230 MW of wind-powered generating facilities between
PacifiCorp and MidAmerican Energy, and the development of 380 MW of wind-powered generating facilities
between PacifiCorp and BHE Renewables, which will qualify for production tax credits
• BHE has funded to date, approximately $840 million renewable tax equity investments
(1) Includes owned operating, under construction and in-development facilities. Excludes tax equity investments
Owned Wind and Solar Generation Capacity (MW)
(1)
Regulated Unregulated
MidAmerican BHE
PacifiCorp Energy NVE Renewables Total
1999-2014 1,030 2,832 - 1,473 5,335
2015 - 581 15 486 1,082
2016 - 594 - 495 1,089
2017-2019 240 2,000 - 322 2,562
Total 1,270 6,007 15 2,776 10,068
Investment (billions) $3 $11 $0 $9 $23
• Our support is explicit from our Aa2/AA rated parent
– BHE is not like any other typical utility holding company. Our balance sheet and credit strength is
supported by a strong owner with over $70 billion of liquidity, as of December 31, 2016
– BHE does not pay dividends, which allows BHE to continue to grow the business and improve
credit quality
– BHE retains more dollars of earnings than any other U.S. electric utility
Berkshire Hathaway Ownership is
Unique to the Utility Industry
(1) As reported by company public filings
(2) Calculated using reported shares outstanding on each respective balance sheet for the period ending December 31, 2016, per S&P Capital IQ
`
($ in millions)
Net Income to
Common(1)
Common
Dividend(1)
Retained
Earnings
per day
Common Dividend
as % of Net
Income
December 31,
2016 Market
Cap(2)
Berkshire Hathaway Energy:
2016 Actual 2,542$ -$ 7.0 0% Privately Held
December 31, 2016:
NextEra Energy 2,912$ 1,612$ 3.6 55% 55,907
Souther Company 2,448 2,104 0.9 86% 48,717
D ke Energy 2,152 2,332 (0.5) 108% 54,334
Dominion Resources 2,123 1,727 1.1 81% 48,099
PPL C rpo ati n 1,902 1,030 2.4 54% 23,145
PG&E Corporation 1,393 921 1.3 66% 30,804
Sempra Energy 1,370 686 1.9 50% 25,175
Edison International 1,311 626 1.9 48% 23,455
Exelon Corporation 1,134 1,166 (0.1) 103% 32,794
American Electric Power 611 1,116 (1.4) 183% 30,958
Peer Median Average 1,648 1,141 1.2 74%
Low Cost Competitive Rates
Company Weighted Average Retail Rate ($/kWh)
Customer Service
Ranking
Pacific Region(1) $0.1447
Pacific Power $0.0948
Mountain Region(1) $0.0954
Rocky Mountain Power $0.0816
Nevada Power $0.0946
Sierra Pacific Power $0.0752
Midwest Region(2) $0.0967
MidAmerican Energy $0.0713
BHE Pipelines Mastio #1
BHE
TQS #1
Score: 96.1%
(1) Source: Edison Electric Institute (Summer 2016)
(2) Source: U.S. Energy Information Administration
Highest Average Rates ($/kWh) by State(1): Hawaii – $0.2395; Massachusetts – $0.1816;
Connecticut – $0.1768; Rhode Island – $0.1717; New York – $0.1674
U.S. National Average(1): $0.1068
Relative to Pacific Region:
Pacific Power 34% lower
Relative to Mountain Region:
Rocky Mountain Power 14% lower
Nevada Power 1% lower
Sierra Pacific Power 21% lower
Relative to Midwest Region:
MidAmerican Energy 26% lower
Berkshire Hathaway Energy
Financial Summary
• Since being acquired by Berkshire Hathaway in March 2000, BHE has realized
significant growth in its assets, net income and cash flows
$6.5
$59.2 $60.8 $62.5
$0.0
$15.0
$30.0
$45.0
$60.0
$75.0
2001 2014 2015 2016
Billions
$0.1
$2.1
$2.4 $2.5
$0.0
$0.7
$1.4
$2.1
$2.8
2001 2014 2015 2016
Billions
$0.8
$5.1
$7.0
$6.1
$0.0
$2.0
$4.0
$6.0
$8.0
2001 2014 2015 2016
Billions
$1.7
$20.4
$22.4
$24.3
$0.0
$5.0
$10.0
$15.0
$20.0
$25.0
2001 2014 2015 2016
Billions
Net Income Attributable to BHE
BHE Shareholders’ Equity Property, Plant and Equipment (Net)
Cash Flows From Operations
Berkshire Hathaway Energy
Growing the Business
$-
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
N
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c
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a
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d
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Flo
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ets
&
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($
bi
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s
)
Total Assets Total Debt Net Income Cash Flows From Operations
(1) Total Debt excludes Junior Subordinated Debentures and BHE trust preferred securities
2001 – 2016 CAGR
Total Assets 13.6%
Net Income 21.2%
Cash Flows From Operations 14.0%
• We have grown our assets significantly since 2001 while de-risking the business, reducing
total debt(1) / total assets from 58% to 43% in 2016 and improving our credit ratings
2015 – 2016 Net Income Variance
Years Ended Dec. 31
($ millions) 2016 2015 Variance
PacifiCorp 764$ 697$ 67$ 10%
MidAmerican Funding 532 442 90 20%
NV Energy 359 379 (20) -5%
Northern Powergrid 342 422 (80) -19%
BHE Pipeline Group 249 243 6 2%
BHE Transmission 214 186 28 15%
BHE Renewables 179 124 55 44%
HomeServices 127 104 23 22%
BHE and Other (224) (227) 3 1%
Net income attributable to BHE 2,542$ 2,370$ 172$ 7%
Return on Equity
(1) Based on 13-point average equity
Net Income Divided by
Average Equity(1)
Entity 2016 2015
Allowed
ROE
PacifiCorp 10.1% 9.3% 9.8%
MidAmerican
Energy
11.1% 10.3% 10.9%
Nevada Power 9.1% 9.6% 9.8%
Sierra Pacific
Power
7.7% 8.0% 9.8%
Northern
Natural Gas
11.2% 11.3% 12.0%
Kern River 10.6% 10.7% 11.55%
• BHE Key Credit Ratios(1)
– Credit ratios continue to be strong and supportive of our credit ratings
• Ratings (issuer or senior unsecured ratings unless noted)
Credit Metrics and Financial Strength
(1) Refer to the BHE Appendix for the calculations of key ratios
(2) 2014 column excludes AltaLink debt and BHE acquisition debt related to AltaLink acquisition
(3) Ratings are senior secured ratings
2016 2015 2014
FFO Interest Coverage 4.3x 4.5x 4.9x
FFO to Adjusted Debt Excluding Acquisition Related Debt (2) 16.0% 17.6% 20.6%
Adjusted Debt to Total Capitalization 59% 59% 60%
Moody’s S&P Fitch Moody’s S&P Fitch DBRS
Berk hire Hathaw y Energy A3 A- BBB+ Northern Natural Gas Company A2 A A -
PacifiCorp
(3) A1 A+ A+ Kern River Funding Corp.
(3) A2 A A- -
MidAmerican Energy Company
(3) Aa2 A+ A+ Northern Powergrid (Northeast) A3 A A- -
Nevada Power Company
(3) A2 A+ A- Northern Powergrid (Yorkshire) A3 A A -
Sierra Pacific Power Company
(3) A2 A+ A- AltaLink, L.P.
(3) - A - A
Regulated Platform Credit Metrics
Note: Refer to the BHE appendix for the calculations of key ratios, excluding AltaLink, L.P. AltaLink financial information is disclosed in the
Management’s Discussion and Analysis section as presented in its Canadian public financial filings
Regulated U.S. Utilities Regulated Pipelines and Electric Distribution
2016 2015 2014 2016 2015 2014
PacifiCorp Northern Natural Gas
FFO Interest Coverage 5.7x 5.4x 5.2x FFO Interest Coverage 9.5x 10.4x 8.3x
FFO to Debt 24.1% 23.2% 22.4% FFO to Debt 41.8% 48.7% 36.6%
Debt to Total Capitalization 50% 49% 48% Debt to Total Capitalization 36% 36% 40%
MidAmerican Energy Northern Powergrid
FFO Interest Coverage 7.8x 7.2x 7.1x FFO Interest Coverage 5.1x 5.1x 5.3x
FFO to Debt 30.4% 26.6% 25.9% FFO to Debt 21.7% 21.2% 24.4%
Debt to Total Capitalization 46% 48% 49% Debt to Total Capitalization 43% 44% 43%
Nevada Power AltaLink, L.P.
FFO Interest Coverage 4.6x 6.1x 4.6x FFO Interest Coverage 3.2x 2.6x 3.0x
FFO to Debt 21.6% 29.5% 21.2% FFO to Debt 11.8% 9.6% 10.4%
Debt to Total Capitalization 51% 51% 55% Debt to Total Capitalization 62% 62% 61%
Sierra Pacific Power
FFO Interest Coverage 5.4x 6.1x 4.9x
FFO to Debt 20.7% 25.7% 19.8%
Debt to Total Capitalization 51% 53% 54%
• Berkshire Hathaway Energy and its subsidiaries will spend approximately $13.6 billion from
2017 – 2019 for development and maintenance capital expenditures, which includes new
generation project expansions, primarily wind, transmission and distribution, and environmental
capital expenditures
Capital Expenditures and Cash Flows
$-
$1,500
$3,000
$4,500
$6,000
$7,500
2012A 2013A 2014A 2015A 2016A 2017F 2018F 2019F 2020F 2021F
$
m
il
li
o
n
s
BHE Cash Flows from Operations BHE Total Capital Expenditures BHE Operating Capital Expenditures
Free Cash Flow
2017 –
2021: $20B
2017 –
2021: $11B
• 2017-2019 capital expenditure projections have increased by $4.6 billion from prior year projections, primarily
due to the Wind XI investment at MidAmerican Energy, the development of solar energy projects at BHE
Renewables, and the repowering of wind facilities at PacifiCorp and MidAmerican Energy, partially offset by
lower growth capital investment at AltaLink
Capital Investment Plan
850 780
985 846
1,620
896
1,691
617
1,709
409
1,649
349
457
403
386
340
376
386
591
546
520
515
420
483
384
354
256
180
344
211
334
74
83
65
86
69
366
542
252
582
231
721
4,673
3,316
4,191
2,937
4,726
3,115
$-
$900
$1,800
$2,700
$3,600
$4,500
$5,400
2017 Current
Plan
2017 Prior
Plan
2018 Current
Plan
2018 Prior
Plan
2019 Current
Plan
2019 Prior
Plan
$
M
ill
io
n
s
PacifiCorp MidAmerican Funding NV Energy
Northern Powergrid BHE Pipeline Group and Other BHE Renewables
BHE Transmission
Financing Plan 2017
• MidAmerican Energy
– In February 2017, issued $850 million of First Mortgage, green bonds comprised of
two tranches: $375 million 10-year offering at 3.10% coupon, and $475 million 30-
year offering at 3.95% coupon
– Anticipate approximately $50 million of tax-exempt debt financing in late 2nd half of
2017
• Nevada Power and Sierra Pacific Power
- Anticipate approximately $115 million of tax-exempt debt financing during 2017
• BHE Renewables
– Anticipate non-recourse project financing of approximately $225 million for the
Alamo 6 Solar project during the first half of 2017
• Northern Powergrid
– Anticipate up to £150 million debt financing in mid-2017 for the development of
smart metering services
• AltaLink, L.P.
– Anticipate debt financing of up to C$200 million in late-2017
Potential Tax Reform
• We are not certain if tax reform will occur, and if so what it will entail
• We expect any changes in law will be reflected in our regulated utilities
revenue requirements. Any reduced tax rate will benefit customers, any loss
of interest deductibility will be a detriment to customers, and any accelerated
tax depreciation for capital will increase cash flow and decrease rate base.
We believe the likely net impact is a reduction in customer rates
• We believe there will be a one-time gain in the year the tax law is enacted
related to the reduction of the tax rate applied to non-regulated deferred
income tax liabilities. If interest is not deductible the interest cost at our
parent and non-regulated subsidiaries will reduce cash flow and earnings,
while accelerated tax depreciation will improve cash flow
• Changes to rules on foreign income taxes may impact future dividend
strategy and capitalization
• We believe BHE is well positioned to adjust to changes made in tax
legislation and we do not believe there will be any material credit impacts to
BHE
Questions
BHE Appendix
Organizational Structure
2016 Berkshire Hathaway Inc. ($ billions)
Revenue $ 223.6
Net Income $ 24.1
Equity $ 283.0
2016 Berkshire Hathaway Energy ($ billions)
Revenue $ 17.4
Net Income $ 2.5
Equity $ 24.3
A3/A-/BBB+
Aa2/AA/A+
90%
Nevada Power
Company
A2/A+/A-(1)
Regulated Electric
Utility
Sierra Pacific Power
Company
A2/A+/A-(1)
Regulated Electric and
Gas Utility
Real Estate
Brokerage, Mortgage
and Franchises
Northern Powergrid
(Northeast) Ltd.
A3/A/A-
U.K. Regulated
Electric Distribution
Regulated
Electricity
Transmission
Contracted
Non-utility Power
Generation
Northern Powergrid
(Yorkshire) plc
A3/A/A
U.K. Regulated
Electric Distribution
A2/A/A-(1)
Regulated Natural
Gas Transmission
A2/A/A
Regulated Natural
Gas Transmission
Baa1/A-/A-
Holding Company
Aa2/A+/A+(1)
Regulated Electric
and Gas Utility
Baa2/A-/BBB-
Holding Company
A1/A+/A+(1)
Regulated Electric
Utility
A/A(1)
S&P, DBRS
Alberta Canada
Regulated Transmission
(1) Ratings for PacifiCorp, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company,
AltaLink L.P., and Kern River Funding Corp. are senior secured ratings
Reportable Segment Information
Years Ended Dec. 31
($ millions) 2016 2015 2014
Operating Income:
PacifiCorp 1,427$ 1,344$ 1,308$
MidAmerican Funding 566 451 395
NV Energy 770 812 791
Northern Powergrid 494 593 674
BHE Pipeline Group 455 464 439
BHE Transmission 92 260 16
BHE Renewables 256 255 314
HomeServices 212 184 125
BHE and Other (21) (35) (16)
Total operating income 4,251 4,328 4,046
Interest expense - senior & subsidiary (1,789) (1,800) (1,633)
Interest expense - junior subordinated debentures (65) (104) (78)
Capitalized interest and other, net 453 311 267
Income before income tax expense and equity income (loss) 2,850 2,735 2,602
Income tax expense 403 450 589
Equity income (loss) 123 115 109
Net income 2,570 2,400 2,122
Net income attributable to noncontrolling interests 28 30 27
Net income attributable to BHE shareholders 2,542$ 2,370$ 2,095$
Rate Base Growth
$16.6 $17.2 $17.4 $17.5
$0.0
$4.0
$8.0
$12.0
$16.0
$20.0
2014A 2015A 2016A 2017F
Billions
$7.0 $6.8 $6.8 $6.9
$0.0
$2.0
$4.0
$6.0
$8.0
2014A 2015A 2016A 2017F
Billions
$6.7
$7.5
$9.0
$9.7
$0.0
$2.0
$4.0
$6.0
$8.0
$10.0
2014A 2015A 2016A 2017F
Billions
NV Energy
MidAmerican Energy PacifiCorp
BHE Pipeline Group
$3.1 $3.1 $3.0 $3.1
$0.0
$1.0
$2.0
$3.0
$4.0
2014A 2015A 2016A 2017F
Billions
Note: Rate base represents mid-year averages
Rate Base Growth
£2.6 £2.7
£2.9 £3.0
£0.0
£1.0
£2.0
£3.0
£4.0
2014A 2015A 2016A 2017F
Billions
$3.5
$5.3
$7.0
$7.5
$0.0
$2.0
$4.0
$6.0
$8.0
2014A 2015A 2016A 2017F
AltaLink, L.P. Northern Powergrid
(1) 2015 includes the addition of AltaLink, L.P., which was acquired on December 1, 2014
(2) Northern Powergrid rate base converted into USD at the June 30 USD/GBP FX rate each year including 1.7106 (2014), 1.5712 (2015), 1.3311 (2016), and
1.2500 (2017 estimate)
(3) AltaLink, L.P. rate base converted into USD at the June 30 CAD/USD FX rate each year including 1.2494 (2015), 1.2924 (2016) and 1.3000 (2017 estimate)
Note: Rate base represents mid-year averages
Berkshire Hathaway Energy
$37.8
$43.1
$45.5 $46.7
$0.0
$10.0
$20.0
$30.0
$40.0
$50.0
2014A 2015A 2016A 2017F
PAC MEC Northern Powergrid BHE Pipeline Group NVE AltaLink, L.P.
(1)
(2) (3)
Billions
C$ Billions
Long-Term Debt Summary
As of December 31, 2016
Consolidated Berkshire Hathaway Energy
Wt. Avg. Wt. Avg.
$ (millions) Coupon Life (Years)
(1)
Berkshire Hathaway Energy - Parent 7,818 5.14% 15.3
PacifiCorp 7,079 5.04% 12.8
MidAmerican Funding 4,592 4.61% 14.4
NV Energy 4,582 5.55% 11.2
Northern Natural Gas Company 795 4.87% 13.3
Kern River Gas Transmission Company 195 4.89% 1.0
Northern Powergrid(2) 2,379 5.37% 9.8
BHE Canada(3) 4,058 3.92% 18.3
BHE Renewables 3,674 4.93% 9.1
Total Berkshire Hathaway Energy Long-Term Debt 35,172 4.94% 13.4
Berkshire Hathaway Energy - Parent Junior Subordinated Debentures 944 3.00% 28.0
Northern Electric Preferred Stock - Perpetual 56 8.06% 30.0
PacifiCorp Preferred Stock - Perpetual 2 6.75% 30.0
Total Berkshire Hathaway Energy Preferred Stock and Jr. Sub. Debentures 1,002 3.29% 28.1
Total Berkshire Hathaway Energy Long-Term Securities 36,174 4.89% 13.8
(1) Weighted average life assumes perpetual preferred stock has an average life of 30 years
(2) USD to GBP exchange rate at $1.2336/pound
(3) CAD to USD exchange rate at $1.3441/USD
Debt Maturities
As of December 31, 2016
Long-Term Debt Maturities(1)
(1) Excludes capital leases
$985
$3,526
$2,078
$1,527
$790
$1,555
$2,054
$1,564
$1,169
$944
$-
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
$
M
ill
io
n
s
PacifiCorp MidAmerican Funding NV Energy
Northern Powergrid BHE Pipeline Group BHE Renewables
AltaLink Berkshire Hathaway Energy
Jurisdictional Strength – Unemployment Rates
Source: Bloomberg, Bureau of Labor and Statistics
(1) Weighted average of Oregon, Utah and Wyoming
58.0%
60.0%
62.0%
64.0%
66.0%
68.0%
70.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
14.0%
2009 2010 2011 2012 2013 2014 2015 2016
U
.S
.
L
a
b
o
r
P
ar
ti
cipat
io
n
U
n
e
mp
lo
y
ment
R
ate
s
Iowa Nevada Alberta U.K. PAC Territory U.S. Labor Participation
(1)
Retail Electric Sales – Actual
December 31 Variance
(GWh) 2016 2015 Actual Percent
PacifiCorp
Residential 16,058 15,566 492 3.2%
Commercial 16,857 17,262 (405) -2.3%
Industrial and Other 21,403 21,814 (411) -1.9%
Total 54,318 54,642 (324) -0.6%
MidAmerican Energy
Residential 6,408 6,166 242 3.9%
Commercial 3,812 3,806 6 0.2%
Industrial and Other 13,704 13,070 634 4.9%
Total 23,924 23,042 882 3.8%
Nevada Power
Residential 9,394 9,246 148 1.6%
Commercial 4,663 4,635 28 0.6%
Industrial and Other 7,525 7,785 (260) -3.3%
Total 21,582 21,666 (84) -0.4%
Sierra Pacific Power
Residential 2,375 2,315 60 2.6%
Commercial 2,933 2,942 (9) -0.3%
Industrial and Other 3,030 2,989 41 1.4%
Total 8,338 8,246 92 1.1%
Northern Powergrid
Residential 12,839 12,718 121 1.0%
Commercial 5,338 5,769 (431) -7.5%
Industrial and Other 17,742 18,093 (351) -1.9%
Total 35,919 36,580 (661) -1.8%
Retail Electric Sales – Weather Normalized
December 31 Variance
(GWh) 2016 2015 Actual Percent
PacifiCorp
Residential 16,135 15,810 325 2.1%
Commercial 16,762 17,163 (401) -2.3%
Industrial and Other 21,360 21,693 (333) -1.5%
Total 54,257 54,666 (409) -0.7%
MidAmerican Energy
Residential 6,297 6,239 58 0.9%
Commercial 3,788 3,816 (28) -0.7%
Industrial and Other 13,703 13,069 634 4.9%
Total 23,788 23,124 664 2.9%
Nevada Power
Residential 9,195 8,933 262 2.9%
Commercial 4,614 4,573 41 0.9%
Industrial and Other 7,475 7,707 (232) -3.0%
Total 21,284 21,213 71 0.3%
Sierra Pacific Power
Residential 2,418 2,311 107 4.6%
Commercial 2,935 2,937 (2) -0.1%
Industrial and Other 3,027 2,981 46 1.5%
Total 8,380 8,229 151 1.8%
Northern Powergrid
Residential 12,937 12,894 43 0.3%
Commercial 5,387 5,761 (374) -6.5%
Industrial and Other 17,793 18,055 (262) -1.4%
Total 36,117 36,710 (593) -1.6%
Retail Load (Weather Normalized)
100,000
105,000
110,000
115,000
120,000
125,000
130,000
135,000
140,000
145,000
150,000
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
2010 2011 2012 2013 2014 2015 2016 2017F
B
H
E
T
ota
l
Weather
N
orma
li
ze
d
G
W
h
Northern Powergrid - CAGR (-1.1%) Rocky Mountain Power - CAGR 0.5% MidAmerican Energy - CAGR 1.9%
Nevada Power - CAGR 0.0% Pacific Power - CAGR -0.5% Sierra Pacific Power - CAGR 1.6%
BHE Total - CAGR 0.2%
Weather
N
orma
li
ze
d
G
W
h
Private Generation Penetration Rate
Total Electric
Customers as of
December 2016
Private Solar
Customers as of
December 2016
Private Solar
Portion of
Total Customers
MidAmerican Energy Company
Iowa 673,408 382 0.06%
Illinois 85,078 18 0.02%
South Dakota 4,915 0 0.00%
PacifiCorp
Utah 882,367 15,902 1.80%
Oregon 576,914 5,228 0.91%
Wyoming 140,580 241 0.17%
Washington 130,206 588 0.45%
Idaho 76,797 218 0.28%
California 45,092 291 0.65%
NV Energy
Nevada 1,245,637 24,146 1.94%
Total BHE Customers 3,860,994 47,014 1.22%
Berkshire Hathaway Energy – Impact of Private Generation
Note: Electric and Private Solar customers represent residential customers only
Consolidated Environmental Position
• Owned coal-fueled capacity has declined as a percentage of BHE‟s generation portfolio from
51% in 2000, to 30% as of December 31, 2016
• Coal Combustion Residuals – managing under new regulatory requirements
– PacifiCorp has 6 active surface impoundments and 4 landfills; 3 inactive surface impoundments are
undergoing closure
– MidAmerican Energy has 3 active surface impoundments and 4 landfills; 4 inactive surface impoundments
are undergoing closure, and 2 have been closed
– NV Energy operates 2 active evaporative surface impoundments and 2 landfills; all other surface
impoundments are undergoing closure by removal
• Effluent Limitation Guidelines
– For BHE‟s operating companies, impacted waste streams are limited to bottom ash or fly ash transport
water, combustion residual leachate and non-metal cleaning wastes
– With minor exceptions, most new requirements are addressed by compliance with the coal combustion
residuals rule
• The U.S. Supreme Court issued a stay February 9, 2016, of the implementation of the Clean
Power Plan pending the outcome of the litigation pending in the D.C. Circuit Court of Appeals
and through any action taken on appeal to the U.S. Supreme Court
– Oral arguments were held September 27, 2016, before ten judges in the D.C. Circuit; decision is expected
in early 2017
• Paris Agreement became effective November 4, 2016, after ratification by the requisite number
of parties representing 55 countries and 55% of global greenhouse gas emissions. Under the
agreement, the U.S. committed to reducing greenhouse gas emissions 26-28% from 2005
levels by 2025. A party cannot withdraw until November 4, 2019, and the withdrawal would
take effect one year later
Reducing Carbon Footprint
• Through fuel switching and retirements, BHE‟s utilities expect to eliminate approximately
2,560 MW of coal generation through 2025
(1) Adjusted for re-rating of coal plants in 2014, 2015, and 2016, including plants still in operation and retired
(2) NV Energy is divesting its interest
Coal MW as of Dec. 31, 2013(1) 10,526 MW
Riverside 3 – retired in 2014 (4) MW
Reid Gardner 1-3 – retired in 2014 (300) MW
Carbon 1 and 2 – removed from service in 2015 (172) MW
Riverside 5 – converted to natural gas in 2015 (124) MW
Walter Scott 1 and 2 – retired in 2015 (124) MW
Neal 1 and 2 – retired in 2016 (390) MW
Reid Gardner 4 – retired in 2017 (257) MW
Cholla 4 – natural gas conversion or retire (395) MW
Naughton 3 – natural gas conversion or retire (280) MW
Navajo – interest to be divested in 2019 (255) MW
North Valmy(2) – to be retired in 2025 (261) MW
Coal MW as of Dec. 31, 2025 7,964 MW
Deliver Reliable and Affordable Service
Mastio Results
Interstate Pipelines 2003 2017
Northern Natural Gas 43 1
Kern River 10 2
TQS Results
2016 Top 5 Utilities on Overall Customer Satisfaction
Rank Utility Very Satisfied
1 Berkshire Hathaway Energy 96.1%
2 Company A 95.9%
3 Company B 93.4%
4 Company C 92.3%
5 Company D 86.6%
47 Company name not available 20.0%
Top 3 for the
13th consecutive year
No. 1 for the
12th consecutive year
Berkshire Hathaway Energy
Non-GAAP Financial Measures
(1) FFO Interest Coverage equals the sum of FFO and Adjusted Interest divided by Adjusted Interest
(2) Debt includes short-term debt, Berkshire Hathaway Energy senior debt, Berkshire Hathaway Energy subordinated debt and subsidiary debt (including current maturities). 2014 Debt has been
restated, and is net of deferred financing costs
(3) FFO to Adjusted Debt Excluding Acquisition Related Debt equals FFO divided by Adjusted Debt Excluding Acquisition Related Debt
(4) Adjusted Debt to Total Capitalization equals Adjusted Debt divided by Capitalization
($ millions)
FFO 2016 2015 2014
Net cash flows from operating activities 6,056$ 6,980$ 5,146$
+/- Changes in other operating assets and liabilities,
net of effects from acquisitions (144) (649) 1,170
FFO 5,912$ 6,331$ 6,316$
Adjusted Interest
Interest expense 1,854$ 1,904$ 1,711$
Interest expense on subordinated debt (65) (104) (78)
Adjusted Interest 1,789$ 1,800$ 1,633$
FFO Interest Coverage(1) 4.3x 4.5x 4.9x
Adjusted Debt
Debt(2) 37,985$ 38,946$ 39,897$
Subordinated debt (944) (2,944) (3,794)
Adjusted Debt 37,041$ 36,002$ 36,103$
Acquisition Financing Debt (1,500)
Acquisition Subsidiary Debt (4,007)
Adjusted Debt Excluding Acquisition Related Debt 37,041$ 36,002$ 30,596$
FFO to Adjusted Debt Excluding Acquisition Related Debt(3) 16.0% 17.6% 20.6%
Capitalization
Berkshire Hathaway Energy shareholders‟ equity 24,327$ 22,401$ 20,442$
Adjusted debt 37,041 36,002 36,103
Subordinated debt 944 2,944 3,794
Noncontrolling interests 136 134 131
Capitalization 62,448$ 61,481$ 60,470$
Adjusted Debt to Total Capitalization(4) 59.3% 58.6% 59.7%
Berkshire Hathaway Energy
Non-GAAP Financial Measures
($ millions)
BHE Consolidated EBITDA Dec-16
Net income attributable to BHE shareholders $2,542
Noncontrolling interests 28
Interest expense 1,854
Capitalized interest (139)
Income tax expense 403
Depreciation and amortization 2,591
EBITDA $7,279
PacifiCorp
Non-GAAP Financial Measures
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities. 2014 Debt has been restated, and is net of deferred financing costs
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
($ millions)
FFO 2016 2015 2014
Net cash flows from operating activities 1,568$ 1,734$ 1,570$
+/- Changes in other operating assets and liabilities 203 (74) 10
FFO 1,771$ 1,660$ 1,580$
Interest expense 380$ 379$ 379$
FFO Interest Coverage(1) 5.7x 5.4x 5.2x
Debt (2) 7,349$ 7,166$ 7,039$
FFO to Debt(3) 24.1% 23.2% 22.4%
Capitalization
PacifiCorp shareholders‟ equity 7,390$ 7,503$ 7,756$
Debt 7,349 7,166 7,039
Capitalization 14,739$ 14,669$ 14,795$
Debt to Total Capitalization(4) 49.9% 48.9% 47.6%
MidAmerican Energy
Non-GAAP Financial Measures
($ millions)
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities. 2014 Debt has been restated, and is net of deferred financing costs
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
FFO 2016 2015 2014
Net cash flows from operating activities 1,403$ 1,351$ 823$
+/- Changes in other operating assets and liabilities (65) (216) 235
FFO 1,338$ 1,135$ 1,058$
Interest expense 196$ 183$ 174$
FFO Interest Coverage(1) 7.8x 7.2x 7.1x
Debt (2) 4,400$ 4,271$ 4,084$
FFO to Debt(3) 30.4% 26.6% 25.9%
Capitalization
MidAmerican Energy shareholder's equity 5,160$ 4,705$ 4,250$
Debt 4,400 4,271 4,084
Capitalization 9,560$ 8,976$ 8,334$
Debt to Total Capitalization(4) 46.0% 47.6% 49.0%
Nevada Power
Non-GAAP Financial Measures
($ millions)
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities. 2014 Debt has been restated, and is net of deferred financing costs
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
FFO 2016 2015 2014
Net cash flows from operating activities 771$ 892$ 704$
+/- Changes in other operating assets and liabilities (109) 77 46
FFO 662$ 969$ 750$
Interest expense 185$ 190$ 208$
FFO Interest Coverage(1) 4.6x 6.1x 4.6x
Debt (2) 3,066$ 3,285$ 3,544$
FFO to Debt(3) 21.6% 29.5% 21.2%
Capitalization
Nevada Power shareholder's equity 2,972$ 3,163$ 2,888$
Debt 3,066 3,285 3,544
Capitalization 6,038$ 6,448$ 6,432$
Debt to Total Capitalization(4) 50.8% 50.9% 55.1%
Sierra Pacific
Non-GAAP Financial Measures
($ millions)
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities. 2014 Debt has been restated, and is net of deferred financing costs
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
FFO 2016 2015 2014
Net cash flows from operating activities 243$ 342$ 246$
+/- Changes in other operating assets and liabilities (4) (33) (10)
FFO 239$ 309$ 236$
Interest expense 54$ 61$ 61$
FFO Interest Coverage(1) 5.4x 6.1x 4.9x
Debt (2) 1,153$ 1,202$ 1,190$
FFO to Debt(3) 20.7% 25.7% 19.8%
Capitalization
Sierra Pacific Power shareholder's equity 1,108$ 1,076$ 998$
Debt 1,153 1,202 1,190
Capitalization 2,261$ 2,278$ 2,188$
Debt to Total Capitalization(4) 51.0% 52.8% 54.4%
Northern Natural Gas
Non-GAAP Financial Measures
($ millions)
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities. 2014 Debt has been restated, and is net of deferred financing costs
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
FFO 2016 2015 2014
Net cash flows from operating activities 367$ 362$ 297$
+/- Changes in other operating assets and liabilities (35) 25 31
FFO 332$ 387$ 328$
Interest expense 39$ 41$ 45$
FFO Interest Coverage(1) 9.5x 10.4x 8.3x
Debt (2) 795$ 795$ 895$
FFO to Debt(3) 41.8% 48.7% 36.6%
Capitalization
Northern Natural Gas shareholder‟s equity 1,409$ 1,410$ 1,330$
Debt 795 795 895
Capitalization 2,204$ 2,205$ 2,225$
Debt to Total Capitalization(4) 36.1% 36.1% 40.2%
Northern Powergrid
Non-GAAP Financial Measures
(£ millions)
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities. 2014 Debt has been restated, and is net of deferred financing costs
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
FFO 2016 2015 2014
Net cash flows from operating activities 382£ 345£ 336£
+/- Changes in other operating assets and liabilities 31 48 54
FFO 413£ 393£ 390£
Interest expense 100£ 95£ 91£
FFO Interest Coverage(1) 5.1x 5.1x 5.3x
Debt (2) 1,906£ 1,858£ 1,601£
FFO to Debt(3) 21.7% 21.2% 24.4%
Capitalization
Northern Powergrid shareholders‟ equity 2,491£ 2,297£ 2,108£
Debt 1,906 1,858 1,601
Noncontrolling interests 36 36 37
Capitalization 4,433£ 4,191£ 3,746£
Debt to Total Capitalization(4) 43.0% 44.3% 42.7%
Bill Fehrman
President and CEO
MidAmerican Energy Company
2017 Fixed-Income Investor Conference
Customer Load
• Economic and Load Data
– Service territory has experienced moderate economic growth
– Forecast loads for 2017 and 2018 reflect a continuation of this trend,
particularly for the industrial class due to announced data center and
biotechnology expansions within MidAmerican Energy‟s service territory
– Data centers attracted to relatively low, stable electric rates and
MidAmerican Energy‟s wind portfolio
0
5
10
15
20
25
30
2011 2012 2013 2014 2015 2016 2017F 2018F
T
W
h
MidAmerican Energy Retail Load
Weather-Normalized
Annual Growth Rates:
2012 = 0.6%
2013 = 1.7%
2014 = 2.6%
2015 = 1.8%
2016 = 2.9%
2017 = 2.5%
2018 = 1.3%
Forecast 2019 Iowa electric net plant
including Wind XI
• 67% of Iowa electric net plant subject to
rate-making principles
• 11.5% weighted average return on equity
• 33 years weighted average remaining life
Rate Status
Annual Growth Rates:
2010 = 4.2%
2011 = 1.2%
2012 = 0.6%
2013 = 1.7%
2014 = 6.7%
2015 = 3.4% Subject to Rate Principles
Subject to General Rate Order
$8,186
67%
$4,019
33%
• No expected need for electric rate base increase
through 2029
• All state jurisdictions have energy and transmission
cost rider recovery mechanisms; Iowa and South
Dakota riders include PTCs from over half of wind
projects currently in-service
• Rate base reductions via Iowa revenue sharing and
other arrangements mitigate the need for future base
rate increases
• Iowa revenue sharing for 2017 reduces rate base for
80% of pre-tax income on ROEs exceeding 11%
• Iowa revenue sharing for 2018 and beyond reduces
rate base for 100% of pre-tax income on ROEs
exceeding a weighted average value calculated
annually; Based on current forecast, trigger would be
10.6% for 2018
• Managing capital and O&M spending to minimize the
need for gas base rate relief
Electric rates among the lowest in the Midwest region and the United States
• Wind repowering efforts planned for oldest 1.5 MW GE turbines in fleet
– 173 turbines (2017), 110 turbines (2018)
– Continued evaluation of remaining 423 GE turbines in fleet
• Operating capital varies with timing of major power generation planned outages and system
requirements
Capital Investment Plan
• 551 MW Wind X project completed on time and under $888 million
regulatory cap in fourth quarter 2016
• Approval received for and construction initiated on 2,000 MW,
$3.6 billion Wind XI project
– 338 MW (2017), 680 MW (2018), 982 MW (2019)
$538
$339
$507 $534
$391
$274
$989
$1,109
$1,130 $1,157 $1,318
$1,375
-
200
400
600
800
1,000
1,200
1,400
1,600
2014 2015 2016 2017F 2018F 2019F
$
M
il
li
on
s
Operating Development
($ millions)
2017-2019
Current
Plan
Prior
Plan
Operating $ 1,199 $ 972
Development 3,850 403
Total $ 5,049 $ 1,375
Wind Repowering
• Equipment was purchased in 2016 sufficient to repower up to 1,059 MW / 706 GE
turbines by 2020, which will qualify for production tax credits
• Plan reflects 424.5 MW (283 turbines) and $494 million total repowering investment
in-service 2017/2018
• Yields net savings for customers
• Minimal environmental impact and permitting
• Depending on the tower height and length of blades that can be installed during
repowering (82.5 meters or 87 meters), repowering will increase annual production by
between 19% and 26%
Illustration of 87m blade change:
New technology
installed with longer
rotors, upgraded
gearboxes and controls
on top of existing towers
and foundations
Build Renewable Energy
Percent of
Iowa Retail
Sales
MW
Installed
Capacity
Cumulative
Investment
($ billions)
2012 Actual 34% 2,285 $3.7
2013 Actual 38% 2,329 $3.8
2014 Actual 39% 2,832 $4.6
2015 Actual 47% 3,448 $5.8
2016 Actual 55% 4,048 $7.0
2017 Plan 63% 4,386 $7.8
2018 Plan 66% 5,066 $8.7
2019 Plan 76% 6,048 $10.2
2020 Plan 89% 6,048 $10.2
MidAmerican Energy’s
Iowa Wind Generation
MidAmerican Energy Participates in the
Midcontinent Independent System Operator
All or some of the renewable attributes associated with the generation have
been or may in the future be: (a) sold to third parties, or (b) used to comply
with future regulatory requirements
The size of MISO‟s non-renewable installed capacity enables
MidAmerican to continue developing wind generation while
maintaining satisfactory reliability. Non-renewable sources
account for 86% of MISO capacity
• In 2015 and 2016, Exelon publicly reported it would retire Quad
Cities Nuclear Station by May 2018, prior to the 2032 expiration
of its operating license
– MidAmerican worked with Exelon on a legislative solution to keep the plant
open
– Future Energy Jobs bill signed into law in Illinois in December 2016
• Provides Exelon annual subsidies through 2027, ensuring continued operation of plant
• No incremental cost to MidAmerican customers; no incremental benefit to
MidAmerican
• MISO MVP transmission projects nearly complete, with $445 million
of the $520 million total costs spent through December 31, 2016
Other Developments
MidAmerican Energy Appendix
MidAmerican Energy Company Overview
• Headquartered in Des Moines, Iowa
• 3,300 employees
• 1.5 million electric and natural gas
customers in four Midwestern states
• 10,595 MW(1) of owned power capacity
(1) Net MW owned in operation and under construction as of Dec. 31, 2016
SOUTH DAKOTA
NEBRASKA
KANSAS MISSOURI
ILLINOIS
WISCONSIN
MINNESOTA
IOWA
MidAmerican Energy
Service Territory
Major Generating Facilities
Wind Projects
Wind XI sites TBD
Rate Base Growth
Note: Rate base represents mid-year averages
$6.7
$7.5
$9.0
$0
$100
$200
$300
$400
$500
$600
$700
$800
$0.0
$2.0
$4.0
$6.0
$8.0
$10.0
2014A 2015A 2016A
O
&
M
($
m
il
li
o
n
s
)
Rate
Base
($
b
il
li
o
n
s
)
MidAmerican Energy
2016 Retail Electric Sales by Class (GWh)
2016 Retail Electric Revenue: $1.7 billion
Residential
27%
Commercial
16%
Industrial
50%
Other
7%
• Private generation activities in Iowa
– Iowa Utilities Board approved MidAmerican‟s net metering tariff as part of
a three year pilot project
• Size cap on system equal to customer‟s “load”
• Annual payout of excess energy: 50% paid to customer; 50% paid to low-income
heating assistance program
• Payout at avoided cost
– Inquiry on avoided costs: proposal to set it at locational marginal price
• MidAmerican Energy‟s approach to private generation
in Iowa
– Focused on keeping costs low for all customers
– Avoid inter-class cross-subsidization through proper rate design
– Considering how to add solar generation options for customers
– Considering how to add energy storage to the system
Private Generation in Iowa
MidAmerican Environmental Position
• Effective with the retirement of Neal Units 1
and 2 in April 2016, MidAmerican Energy
has 2,708 MW(1) of coal-fueled generation
capacity remaining
• Projected environmental capital spend(2)
– $193 million from 2017-2019
(1) Net owned capacity as of December 31, 2016
(2) Environmental capital expenditures forecast excludes equity AFUDC
(3) Net MW owned in operation and under construction
Asset Profile
84%
2%
14%
Renewables
and Other
Natural Gas
Generation
Coal
Generation
Net Property, Plant and Equipment as of December 31, 2016
December 31, 2000
Power Capacity – 4,086 MW (3)
December 31, 2016
Power Capacity – 10,595 MW (3)
Coal
26%
Natural Gas
13%
Nuclear and
other
4%
Wind
57%
Coal
70%
Natural
Gas
19%
Nuclear
and Other
11%
• Recoveries for transmission service in MISO for MidAmerican Energy-
owned regional transmission assets were based on 12.38% return on
equity prior to September 28, 2016
• Two FERC complaint dockets seek to lower base ROE to 9.15% and
8.67% for periods beginning November 2013 and March 2015,
respectively
• FERC decision in the first complaint effective September 28, 2016
ordered 10.32% ROE (before incentive adders)
• ROE refunds in first case expected to be fully processed by May 2017
• Preliminary decision by administrative law judge in second complaint
recommending 9.70% ROE (before incentive adders) pending before
the FERC Commissioners
• Immaterial refund reserve established for the period from November
2013 through May 2016 consistent with 15 month refund obligations
• Final decision in the second case expected mid-2017
MISO ROE Proceedings
Stefan Bird Cindy Crane
President and CEO
Rocky Mountain Power
President and CEO
Pacific Power
2017 Fixed-Income Investor Conference
PacifiCorp Retail Sales
2016 compared to 2015 down 0.7%
• Industrial sales down 2.5%
• Commercial sales down 2.3%
• Residential sales up 2.1%
2017 forecast vs. 2016 down 0.5%
• Industrial sales - higher due to modest
extraction industry growth
• Commercial sales - higher due to
economic growth partially offset by
efficiencies
• Residential sales - lower due to use per
customer reductions more than offset
growth in new customers 0
7
14
21
28
35
42
49
56
63
2011 2012 2013 2014 2015 2016 2017F 2018F
T
W
h
PacifiCorp Retail Sales
(weather-normalized)
Annual Growth Rate
2012 = 0.1%
2013 = 0.3%
2014 = 1.2%
2015 = (0.9%)
2016 = (0.7%)
2017 = (0.5%)
2018 = (0.3%)
PacifiCorp Capital Expenditures
($ millions)
2017-2019
Current
Plan
Prior
Plan
Operating $ 1,648 $ 1,790
Development 1,807 732
Total $ 3,455 $ 2,522
$603 $660 $569 $564 $501 $583
$463 $256 $334 $286 $484
$1,037
-
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2014 2015 2016 2017F 2018F 2019F
$
M
il
li
on
s
Operating Development
2017-2019 forecast vs. prior plan up $933 million
• $1,075 million higher development capital expenditures leverage
safe harbor investments to deliver cost-effective fleet repowering and
greenfield wind opportunities in-service by 2020. Yields net savings to
customers
- 240 MW additional wind (2020)
- 805 MW repowered wind (2019/2020)
• $142 million lower operating capital expenditures, primarily in thermal
generation due to new operating environment
Wind Repowering & New Development
New technology
installed with longer
rotors, upgraded
gearboxes and controls
on top of existing towers
and foundations
Illustration of 87m blade change:
• New wind development of 240 MW with an anticipated cost of $377.2 million
is expected to be completed by 2020
• Wind repowering
- Equipment was purchased in 2016 sufficient to repower the entire 1,030 MW wind
fleet by 2020, which will qualify for production tax credits
- Plan reflects 805 MW and $916.5 million total repowering investment by 2020
- Yields net savings for customers
- Minimal environmental impact and permitting
Energy Imbalance Market
• $142.6 million aggregate EIM footprint
customer benefits realized November 2014
to December 2016
– $76.4 million benefits to PacifiCorp
customers
• Optimizes generation and transmission to
serve customer demand across the entire
EIM footprint in a 5-minute market
• Low cost renewable energy imports from
California are increasingly displacing fossil
generation in low load periods; fossil plants
provide low cost flexible ramp service
• Benefits grow as market expands
– Fall 2017 Portland General Electric
– Spring 2018 Idaho Power Company
– Spring 2019 Seattle City Light
– Spring 2019 BANC/SMUD
Advanced Metering Infrastructure Projects
Scope Benefits
• $146.4 million investment
• Oregon
o 590,000 smart meters
o In-service Jan 2018 – Dec 2019
• Idaho
o 79,000 smart meters
o In-service Dec 2019
• Further deployments being assessed
• Project cost savings fully offset
investment/operating cost
• Customers gain access to near real-time
consumption data and information to
proactively manage their monthly usage
• Improved outage detection and response
• Improved connect/disconnect service
• Improved system monitoring for real-time
operations and distribution system planning
0
5
10
15
20
2011 2012 2013 2014 2015 2016 2017F 2018F
T
W
h
Pacific Power
Retail Sales
Weather Normalized
2012 = (0.4)%
2013 = 0.0%
2014 = 1.3%
2015 = (0.5%)
2016 = 0.4%
2017 = (3.5%)
2018 = (0.5%)
Annual Growth Rate
Pacific Power Retail Sales
497 GWh (-3.8%)
115 GWh (-2.8%)
7 GWh (-0.9%) 2017 forecast sales compared to 2016 down 3.5%
• Industrial sales – lower due to loss of large industrial customer
• Commercial sales – slight decline, due in part to efficiency in
equipment and lighting partially offset by economic growth and
expansion of data centers
• Residential sales – lower due to decline in use-per-customer,
partially offset by new customer growth
Oregon (authorized ROE 9.8%)
• No general rate case in the near future; last general rate case filed in 2013
• Transition Adjustment Mechanism rate increase of $11.7 million or 0.9% for changes
in forecast net power costs and production tax credits, effective January 1, 2017
Washington (authorized ROE 9.5%)
• Approved two-year rate plan with rate increase of 1.7%, effective October 2016;
second step increase of 2.3% effective September 2017
– Incorporates accelerated coal depreciation and new decoupling mechanism
– Earliest next case could become effective is mid-2018
California (authorized ROE 10.6%)
• Next general rate case deferred until January 1, 2019, effective date; last general
rate case filed in 2009
• Energy Cost Adjustment Clause and Greenhouse Gas and Revenues Application
rate reduction of $4.9 million (3.8%), for changes in forecast net power costs and
greenhouse gas costs and revenues, effective January 1, 2017
• Post Test Year Adjustment Mechanism for inflation-based cost increases of
$1.5 million (1.2%), effective January 1, 2017
Pacific Power Regulatory Update
• Senate Bill 1547 was signed into law March 8, 2016
– Increases renewable portfolio standard to 27% by 2025, 35% by 2030, 45% by
2035, 50% by 2040
• Pacific Power compliance position is sufficient until 2028
– Removes coal from Oregon rates by January 1, 2030
– Incorporates production tax credits in annual power cost mechanism
– Establishes community solar program
• Community solar rulemaking currently underway will result in implementation
rules by July 2017
– Authorizes utilities to invest in electric vehicle charging
• Electric utility transportation electrification proposals are under review by the
Commission with resolution expected in late 2017 or early 2018
– Maintains level playing field for service territory acquisitions by requiring acquirer
to meet RPS requirements and pay for any stranded costs
Oregon Clean Electricity
and Coal Transition Plan Update
Cindy Crane
President & CEO
Rocky Mountain Power
Rocky Mountain Power Retail Sales
269 GWh (1.1%)
88 GWh (1.0%)
16 GWh (-0.5%)
2017 forecast sales compared to 2016 up 0.9%
• Industrial sales – higher due to improved economic
conditions and market pricing
• Commercial sales – higher due to economic growth,
partially offset by energy efficiency programs
• Residential sales – lower due to decline in use-per-
customer, partially offset by new customer growth
0
8
16
24
32
40
2011 2012 2013 2014 2015 2016 2017F 2018F
T
W
h
Rocky Mountain Power
Retail Sales
Weather Normalized
2012 = 0.4%
2013 = 0.5%
2014 = 1.2%
2015 = (1.0%)
2016 = (1.3%)
2017 = 0.9%
2018 = (0.1%)
Annual Growth Rate
Rocky Mountain Power
Regulatory Update
Utah (authorized ROE 9.8%)
• No general rate case in near future; last general rate case filed in 2014
• Energy Balancing Account filing to recover $15.0 million in deferred net power costs,
reduced rates 0.8% effective November 1, 2016
Wyoming (authorized ROE 9.5%)
• No general rate case in near future; last general rate case filed in 2015
• Energy Cost Adjustment Mechanism filing to recover $12.2 million in deferred net
power costs, reduced rates 0.5% effective November 1, 2016
Idaho (authorized ROE 9.9%)
• No general rate case in near future; last general rate case filed in 2011
• Energy Cost Adjustment Mechanism filing to recover $16.7 million in deferred net
power costs, reduced rates 0.7% effective April 1, 2016
• Filing to adjust net power costs in base rates reduced by $1.0 million (0.4%) effective
January 1, 2017
Utah Sustainable Transportation
and Energy Plan
• Senate Bill 115 signed into law March 30, 2016
• Phase I approved:
– Capitalization and amortization of demand side management costs and creation
of the coal plant risk mitigation fund
– Net power cost true-up changed to 100%
– Renewable Energy Tariff
– Funding budget of $50.0 million from 2017 through 2021, surcharge rates
replace discontinued Utah Solar Incentive Program
– Projects approved:
• NOx clean coal technology programs ($1.4 million)
• Solar and Energy Storage Program ($5.0 million)
• Gadsby Curtailment Program ($0.5 million)
• Phase II pending: (approval by July 1, 2017)
– Electric Vehicle Program ($10.0 million)
• Commercial Charger Incentives
• Residential Time of Use Tariff
• Utah customers are pursuing clean energy goals
Renewable Development Projects
• In addition to wind development, PacifiCorp is pursuing solar projects in
response to customer demand for renewables
– Focused on company-owned properties to mitigate development costs and risks
– >50 MW sites for potential of ~440 MW new solar development to capture
Investment Tax Credit for benefit of customers
100% communitywide
renewable by 2032
Reduce emissions 15%
in 15 years
100% communitywide
renewable by 2032
Carbon neutral
by 2050
Rocky Mountain Power
Utah Net Metering
• Phase I completed in 2015
– Adopted framework for assessing net metering costs and benefits
– Limited to quantifiable costs/benefits
• Company filed in November 2016 to initiate second phase of docket to implement framework
– Close current net metering tariff to new service
– Implement transitional tariff
– Establish new residential schedule with a 3-part rate design for new private customer generators
• Negotiations underway with parties to determine if resolution of issues can be achieved;
litigation schedule established with hearings in August 2017
1,548
2,222
3,572
6,690
16,689
18,137
-
5,000
10,000
15,000
20,000
2012 2013 2014 2015 2016 2017
YTD
Utah Net Metering
Cumulative Interconnections
Residential Non-Residential Total
PacifiCorp Appendix
PacifiCorp Overview
• Six-state service territory
‒ Utah – Oregon
‒ Idaho – Washington
‒ Wyoming – California
• 5,600 employees
• 1.8 million electricity customers
• 143,000 square miles of service
territory
• 16,500 transmission line miles
• 10,894 MW(1) owned power
capacity
(1) Net MW owned in operation as of December 31, 2016
Rate Base Growth
Note: Rate base represents mid-year averages
$16.6 $17.2 $17.4
$0
$200
$400
$600
$800
$1,000
$1,200
$0.0
$4.0
$8.0
$12.0
$16.0
$20.0
2014A 2015A 2016A
O
&
M
($
m
il
li
o
n
s
)
Rate
Base
($
b
il
li
o
n
s
)
PacifiCorp Retail Sales
2016 Retail Sales by Class (GWh) 2016 Retail Sales by State (GWh)
2016 Retail Electric Revenue: $4.9 billion
Residential
30%
Commercial
31%
Industrial &
Irrigation
38%
Other
1%
California
1%
Oregon
24%
Washington
7%
Idaho
7%
Utah
44%
Wyoming
17%
PacifiCorp Power Capacity and Asset Profile
Power Generating fleet increase primarily
attributed to:
• 1,654 MW Natural Gas - Lake Side 1 & 2
and Chehalis
• 998 MW Wind - 594 MW Eastside and
404 MW Westside
• (172) MW Coal - retired Carbon plant
Asset Profile
69%
9%
22%
Renewables and
Other
Natural Gas
Generation
Coal Generation
Net Property, Plant and Equipment as of December 31, 2016
Coal
55%
Gas
25%
Hydro
10%
Wind and
Other
10%
Coal
72%
Gas
13%
Hydro and
Other
15%
March 31, 2006
Power Capacity – 8,470 MW (1)
December 31, 2016
Power Capacity – 10,894 MW (1)
(1) Net MW owned in operation and under construction
PacifiCorp Environmental Position
Arizona
• EPA issued the pre-publication version of its approval of Arizona‟s amended Regional Haze state implementation plan (SIP) on
January 13, 2017, allowing Cholla Unit 4 to remain coal-fueled through April 2025 with the commitment to cease coal-fueled
operation at that time, and avoiding the retrofit of selective catalytic reduction (SCR)
Colorado
• PacifiCorp and the owners of Craig Unit 1 have agreed with state and federal agencies and environmental groups to amend the
Colorado Regional Haze SIP to allow Unit 1 to retire by December 31, 2025, or convert to natural gas under certain schedule
requirements in lieu of installation of SCR. State of Colorado approval of the alternative is expected during the 2017 state
legislative session. EPA review and approval will follow thereafter
Utah
• EPA published its final action on the updated Utah Regional Haze SIP in the Federal Register on July 5, 2016, requiring SCR on
Hunter Units 1 and 2 and Huntington Units 1 and 2 by August 4, 2021. PacifiCorp has filed a request for reconsideration and
request for administrative stay with EPA, and subsequently filed petitions for judicial review and stay with the 10th Circuit Court. A
court order on the stay request is expected by April 2017
Wyoming
• Effective March 3, 2014, EPA issued a federal implementation plan (FIP) for the Wyodak plant, requiring the installation of SCR
within five years (i.e., by 2019). The 10th Circuit Court issued a day-for-day stay on the Wyodak requirement in September 2014.
The Court‟s decision on the appeals will not likely occur until late-2017, at the earliest
• PacifiCorp continues to assess compliance options for the 280 MW Naughton Unit 3, including conversion to natural gas or
accelerated retirement in lieu of SCR and baghouse retrofits prescribed by the Wyoming Regional Haze SIP(1)
Environmental Expenditures
• Forecast(2) environmental expenditures include $58 million in 2016, $32 million in 2017, $21 million in 2018 and $14 million in
2019
(1) The state of Wyoming is currently finalizing a Naughton Unit 3 permit amendment that will provide the option for natural gas conversion to occur up to one year following
EPA’s approval of the Wyoming Regional Haze state implementation plan requirements for Naughton Unit 3. The state’s amended p lan is yet to be submitted to EPA for review
and approval
(2) Environmental expenditures forecast includes PacifiCorp’s share of minority-owned Craig, Cholla, Colstrip and Hayden plants. Amounts include debt AFUDC and escalation
but exclude non-cash equity AFUDC
PacifiCorp Major Transmission Projects
• Wallula-to-McNary
– Permitting near complete, in-service 2018
• Gateway West
– BLM record of decision on 8 of 10 segments
November 2013
– Remaining two segments across Idaho record
of decision issued January 2017
• Gateway South
– BLM record of decision December 2016
• Boardman-to-Hemingway
– BLM record of decision expected
second quarter 2017
• Segments In-Service
– Populus-to-Terminal November 2010
– Mona-to-Oquirrh May 2013
– Sigurd-to-Red Butte May 2015
Over $6 billion total cost planned; $1.6 billion placed in-service
Paul Caudill
President & CEO
NV Energy
2017 Fixed-Income Investor Conference
0
2
4
6
8
10
2011 2012 2013 2014 2015 2016 2017F 2018F
T
W
h
Sierra Pacific Power Co.
Energy Retail Load (Weather-Normalized)
0
6
12
18
24
2011 2012 2013 2014 2015 2016 2017F 2018F
T
W
h
Nevada Power Co.
Energy Retail Load (Weather-Normalized)
NV Energy Customer Load
System Load Comparison 2016 versus 2015
Nevada Power Company
• Commercial up 0.9% led by retail expansion
• Residential up 1.0% due to customer growth(1)
• Industrial down 3.1% due to customer migration
to distribution only service (MGM Resorts
International, Wynn Las Vegas)
Sierra Pacific Power Company
• Industrial up 1.6% primarily led by manufacturing
• Residential up 2.6% based on customer growth(1)
• Large mining down 0.2% due to low metal prices
Load Forecast For 2017 and 2018
Nevada Power Company
• Customer migration to distribution-only service
reduces load in 2017, while retail and
manufacturing loads help drive non-residential
load growth in 2018
Sierra Pacific Power Company
• Increasing data center and manufacturing loads
will help drive non-residential load growth
Annual Growth Rate
2012 = 3.3%
2013 = 2.2%
2014 = 0.4%
2015 = 1.7%
2016 = 1.8%
2017 = 0.4%
2018 = 3.8%
Annual Growth Rate
2012 = 0.8%
2013 = 0.1%
2014 = (0.8%)
2015 = 1.7%
2016 = 0.3%
2017 = (3.1%)
2018 = 1.4%
(1) Does not reflect the impact of billing changes for private generation
Capital Investment Plan
• Capital investment for 2017-2019 increased
$89.0 million from prior plan primarily due to
additional electric delivery new business and
transmission system reinforcement projects
$388
$522 $528
$302 $295 $310
$170
$49 $1
$155
$91 $66
-
100
200
300
400
500
600
2014 2015 2016 2017F 2018F 2019F
$
M
il
li
on
s
Operating Development
($ millions)
2017-2019
Current
Plan
Prior
Plan
Operating $ 907 $ 981
Development 312 149
Total $ 1,219 $ 1,130
NV Energy Regulatory Update
Nevada Power Company
• 2016 Integrated Resource Plan Amendment
– December 2016, Public Utilities Commission of Nevada:
• Approved proposed 100 MW power purchase agreement with Techren Solar LLC
• Authorized early retirement of 257 MW Reid Gardner Station Unit 4, utilizing must-run
status through March 11, 2017, to burn existing coal stockpile
• 2017 Deferred Energy Accounting Adjustment
– March 2017, filing submitted to Public Utilities Commission of Nevada
– Resets public policy rates for energy efficiency and renewable energy programs
• 2017 Regulatory Rate Review
– Preparations underway for triennial rate review proceeding before the Public Utilities
Commission of Nevada; filing will be made by June 5, 2017
– Focus on no increase in revenue requirement, will likely result in adjustments to individual
customer class rates
NV Energy Regulatory Update
Sierra Pacific Power Company
• 2016 Integrated Resource Plan
– December 2016, Public Utilities Commission of Nevada order:
• Approved energy efficiency programs, two transmission investments, energy supply plan
• Denied acquisition of South Point Energy Center due to energy choice initiative uncertainty
• NV Energy filed a petition for reconsideration
– February 2017, Public Utilities Commission of Nevada continued to deny acquisition of
South Point Energy Center; asset purchase agreement terminated
• 2016 Regulatory Rate Review
– December 2016, Public Utilities Commission of Nevada approved overall customer rate
reduction; reestablished six additional megawatts of private generation at full retail rate
– January 2017, petition for reconsideration filed addressing private generation six megawatts
– February 2017, Public Utilities Commission of Nevada issued order granting itself an open-
ended period of time to take action on private generation petition for reconsideration
• 2017 Deferred Energy Accounting Adjustment
– March 2017, gas and electric filings submitted to Public Utilities Commission of Nevada
– Resets public policy rates for energy efficiency and renewable energy programs
Energy Imbalance Market Progress
• Provides efficient method for balancing
supply and demand through automated
dispatch by a market operator (California
ISO)
• Pre-energy imbalance market NV Energy
balanced supply and demand using
internal resources
• Post-energy imbalance market balancing
occurs regionally with more diverse
resource portfolio, including integration of
renewable energy (solar and wind)
• NV Energy entered the market December
2015
• Captured $13.5 million of transactional
benefits from energy purchases and sales
since entering the EIM
• Benefit range presented to Public Utilities
Commission of Nevada of $6.0 million to
$9.5 million in 2017
Net Energy Metering Update
0
5,000
10,000
15,000
20,000
25,000
2012 2013 2014 2015 2016 2017 YTD
NV Energy Private Generation
Cumulative Interconnections
Residential Non-Residential
In 2016, Private Generation customers represented
approximately 2% of NVE’s total electric customers
• September 2016, NV Energy and stakeholders including members of private
generation industry entered into stipulation to grandfather 32,000 private solar
generation customers; Public Utilities Commission of Nevada accepted stipulation
• December 2016, Public Utilities
Commission of Nevada recognized in
Sierra Pacific Power regulatory rate review:
– Existence of cost shift from private generation
customers
– Rate utility pays for excess energy from
private generation should reflect energy
market
– Private generation customers previously
viewed as separate customer class for
establishing rates
• March 2017, NV Energy and stakeholders
filed petition with Public Utilities
Commission of Nevada to extend period for
eligible customers to opt-in to
grandfathered rates until July 1, 2017
Major Customer Applications to Utilize
Alternate Energy Provider
Inactive
Applicant Peak Load (MW) Impact Fee Status
Las Vegas Sands
Corporation
29 $23.97m
Application approved 2015; compliance items
not satisfied
Peppermill Resorts 10 Undetermined Application withdrawn
Approved
Applicant Peak Load (MW)(1) Impact Fee Status
MGM Resorts
International (south)(2)
174 $82.2m Transition completed October 2016
Wynn Las Vegas(2)
(south)
20 $15.3m Transition completed October 2016
Switch, Ltd. (south) 34 $27.0m
Amended application approved December 2016
Transition estimated June 1, 2017
Switch, Ltd. (north) Under construction $0.00
Amended application approved December 2016
Transition estimated June 1, 2017
Caesars Enterprise
Services, LLC(2) (south)
87 $44.0m
Application approved March 2017; estimated
transition of September 1, 2017
Caesars Enterprise
Services, LLC (north)
10 $3.5m
Application approved March 2017; estimated
transition of September 1, 2017
Total 325 $172.0m
(1) Peak load on July 28, 2016 of 7,966 MW (6,124 at Nevada Power and 1,842 at Sierra Pacific Power)
(2) On-going non-bypassable charges apply
Energy Choice Initiative
Background
• Energy Choice Initiative was a ballot initiative that amends the Nevada State
Constitution “to open Nevada‟s energy markets and give consumers the
option to purchase renewable energy and lower overall energy costs”
• Initiative sponsored by Nevadans for Affordable, Clean Energy Choices
Political Action Committee
– Primary sponsors are Las Vegas Sands Corporation and Switch Ltd.
• Initiative was placed on November 2016 general ballot as Question 3
– “Shall Article 1 of the Nevada Constitution be amended to require the Legislature to
provide by law for the establishment of an open, competitive retail electric energy
market that prohibits the granting of monopolies and exclusive franchises for the
generation of electricity?”
• In the November 2016 general election, the initiative was approved by 72%
of voters
• Initiative will appear on the November 2018 ballot, and must pass again with
a majority vote in order for the Nevada State Constitution to be amended
• If initiative passes in November 2018, the legislature will be required by
Nevada State Constitution to provide implementing laws by July 1, 2023
Energy Choice Initiative
Executive Order Issued February 9, 2017
• Nevada Governor Sandoval issued executive order establishing the
Governor‟s Committee on Energy Choice
• Purpose is to review, evaluate and develop written plans for the full
implementation of energy choice by 2023, provided the initiative again
passes by a vote of the people in 2018
• Appointed Nevada lieutenant governor as chair to 22-member committee,
comprised of:
– Attorney general of the state of Nevada
– Two members each of the Nevada State Senate and the Nevada State Assembly
– Consumer advocate of the Bureau of Consumer Protection
– Appointment of remaining 15 members from NV Energy, rural/municipal co-op utility, large
consumers of electricity, small to mid-sized businesses, Nevada Resort Association, mining,
organized labor, senior citizen organizations, renewable energy industries, homebuilders
and conservation organizations
– Non-voting committee members include a member of Public Utilities Commission of Nevada,
Nevada Governor‟s Office of Energy and Office of Economic Development
• Report of recommendations due to Nevada governor no later than
July 1, 2018, in advance of second vote in 2018 general election
Simple Framework to a Complex Transition
Regulated and efficient
competitive market
July 2023
Level playing field for
all retail providers
Customer protections
MARKET POLICY
564 jobs/$91.9 million payroll
$3.2 billion owned generation
assets $4.2 billion energy contract
obligations (NPV 2020-2046)
NO STRANDED ASSETS
Wholesale market
structure
Retail market structure
State regulatory
functions
Default and provider of
last resort services
Transmission and
distribution services
Energy policies and
programs
COMPLEXITY,
RISKS & COST
Resource adequacy
Renewable and
economic development
Energy efficiency
ENERGY POLICY
No structural winners
and losers
No increase in prices
paid over current model
Reliable service
CUSTOMERS
NV Energy
Respects Public Policy
Transition Plan 2018
• Market Structure
• Competitive Services
• Regulatory Framework
• Restructuring and Transition Costs
Fundamental Assumptions
Consistent with the Energy Choice Initiative ballot language, the following may
be assumed:
• Power generation and energy supply will be established as a competitive
service; will require utilities to divest of existing power plants, power
purchase agreements and gas transportation contracts
– NV Energy, and any affiliates, will be out of the power generation side of the
business in order to prohibit the grant of monopolies for the supply of electricity
• Transmission and distribution service will remain a regulated rate of return
service due to the cost of duplicating investments
– Consistent with what has been done in other fully competitive retail jurisdictions
– Legislature need not provide for transmission and distribution deregulation to
establish the competitive retail market
• Default or provider of last resort service will not be provided by regulated
utilities in order to prevent the grant of an exclusive monopoly
– NV Energy will not provide default or provider of last resort services
• Jobs for NV Energy colleagues will remain a primary focus of decision
makers in the transition
NV Energy Appendix
NV Energy Today
• Headquartered in Las Vegas, Nevada, with
major operations in Reno, Nevada, area
• 2,466 employees
• 1.25 million electric and 162,000 gas customers
• Service to 90% of Nevada population, along
with tourist population in excess of 45 million
• 6,138 megawatts of owned power generation
• Provides electric services to
Las Vegas and surrounding
areas
• 910,000 electric customers
• 4,766 megawatts of owned
power generation capacity(1)
• Provides electric and gas
services to Reno and northern
Nevada
• 340,000 electric customers and
162,000 gas customers
• 1,372 megawatts of owned
power generation capacity(1)
Nevada Power Company Sierra Pacific Power Company
(1) Net summer peak megawatts owned in operation as of December 31, 2016
Rate Base Growth
Note: Rate base represents mid-year averages
$7.0 $6.8 $6.8
$0
$100
$200
$300
$400
$500
$600
$0.0
$2.0
$4.0
$6.0
$8.0
2014A 2015A 2016A
O
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M
($
m
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)
Rate
Base
($
b
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)
NV Energy
2016 Retail Electric Sales by Class (GWh)
Residential
43%
Commercial
22%
Industrial
34%
Other
1%
Nevada Power
Total 2016 Retail Electric Revenue:
$2.0 billion
Total 2016 Retail Electric Revenue:
$0.7 billion
Residential
29%
Commercial
35%
Industrial
36%
Sierra Pacific Power
Customer Retention
Price and Service Improvements
• Nevada Power average monthly residential bill lower today than in 2007
– Based on average usage of 1,141 kilowatt-hours
– $140.77 January 2017 versus $141.91 October 2007
– 2017 mandatory general rate review objective would be no change or
reduction in the revenue requirement, similar to 2014
• Sierra Pacific Power average monthly residential bill lower today than in
2007
– Based on average usage of 743 kilowatt-hours
– $76.98 January 2017 versus $98.50 July 2007
– 2016 general rate case settlement resulted in $2.9m reduction to the
electric revenue requirement
• In 2016, NV Energy received its best TQS Inc. survey score ever of 93.5%
for large commercial and industrial customers, a 1.6% improvement from
2015 and 5.4% increase from 2014
NV Energy Environmental Position
• NV Energy is reducing use of coal-fueled
generation
– 2017 retirement of Reid Gardner Unit 4 (257 MW)
– 2019 elimination of Navajo interest (255 MW)
– 2025 retirement of North Valmy (261 MW)
• Forecast(1) environmental expenditures include
$4 million in 2017, $5 million in 2018 and $7
million in 2019
Nevada Power Asset Profile
64%
33%
3%
Renewables and Other Natural Gas Generation
Coal Generation
Net Property, Plant and Equipment as of December 31, 2016
Sierra Pacific Power Asset Profile
74%
19%
7%
Renewables and Other Natural Gas Generation
Coal Generation
Net Property, Plant and Equipment as of December 31, 2016
December 31, 2016
Power Capacity – 6,138 MW (2)
Coal and
Other
13%
Natural Gas
87%
(1) Environmental capital expenditures forecast excludes equity AFUDC
(2) Net MW owned in operation and under construction
• Navajo Generating Station is a 2,250 megawatt coal-fired facility in-service in 1974
near Page, Arizona, on the Navajo Nation American Indian Reservation
• Six owners: NV Energy, Salt River Project (operator), Arizona Public Service, Tucson
Electric, Los Angeles Department of Water and Power, and U.S. Bureau of Reclamation
• NV Energy‟s ownership level (11.3% or 255 megawatts of the facility) resulted in the
following amounts for 2016:
– Operations and maintenance expense of $19.7 million
– Capital expense of $5.8 million
– Year-end undepreciated value of the plant of $57.1 million
• February 2017, owners communicated lease will not be extended beyond expiration
of December 22, 2019, for plant, water, coal and transmission
• Discussion is underway between Salt River Project and the Navajo Nation to draft
agreements necessary to operate through December 22, 2019
• If agreement is not reached by July 1, 2017, owners will begin decommissioning,
demolition and remediation of the plant as required by the existing lease end date
• March 2017, stakeholder meeting held in Washington D.C. to discuss long-term
options for continued plant operation; follow-up meeting scheduled April 12, 2017
Navajo Generating Station
• Nevada Senate Bill 123, passed in 2013, already required NV Energy to eliminate its
interest in the Navajo Generating Plant by December 31, 2019
– As part of the 2013 law, NV Energy was required to file a plan with the Public Utilities
Commission of Nevada to reduce coal-fired generation under the emissions reduction and
capacity replacement plan
– NV Energy filed the plan in 2014, and approved by Public Utilities Commission of Nevada
• Emissions reduction and capacity reduction plan allows for recovery of costs
necessary to decommission, demolish and remediate the Navajo Generating Station
site, as well as the undepreciated value of the plant at the time of retirement or
elimination
• Impact to NV Energy is minimal, as an early shutdown in 2017, would eliminate
operating and maintenance expense related to operating Navajo Generating Station,
allow for recovery of costs necessary to retire and remediate the plant and would
eliminate a minimum dispatch provision, which would enable additional economic
purchasing of energy for customers
Navajo Generating Station
Bill Fehrman
President and CEO
BHE Renewables
2017 Fixed-Income Investor Conference
BHE Renewables
2016 Update
Solar
• Community Solar Gardens
– 66 MW community solar gardens project acquired in January 2016 and is 91.1% subscribed
– 32 MW community solar gardens project acquired in 2015, started commercial operation as
of February 1, 2017, and is 100% subscribed
• Alamo 6
– 110 MW project acquired in January 2017, with commercial operation achieved in March
2017
• Solar Star 1
– Had two unplanned outages in 2016. There are now four spare transformers on site
• Topaz and Agua Caliente
– Both projects had high availability and generation above budget for 2016
BHE Renewables
2016 Update
Wind
• Marshall Wind
– 72 MW project acquired in September 2015, commercial operation under its PPAs started in
May 2016
• Grande Prairie Wind
– 400 MW project completed in November 2016, commercial operation under its PPA started in
December 2016
• Pinyon Pines, Jumbo Road and Bishop Hill
– All projects had high availability and near budgeted generation despite lower than expected
wind resource
• Tax Equity
– Funded renewable tax equity investments, including $170 million in 2015, $584 million in
2016, and $85 million in 2017
Renewables Opportunities
• BHE Renewables is pursuing a diversified strategy for growth, including:
– Continuing to pursue direct ownership of utility-scale wind and solar assets with
long-term offtake agreements
– Tax equity investment opportunities for hedged or contracted utility-scale wind
projects
• Kingfisher, South Plains II, Shannon, Mariah and New Creek have all been funded
• Chapman Ranch is secured under a definitive agreement
– Wind repowering is currently not economical at BHE Renewables as our
turbines are relatively new, still within the PTC period and have already
implemented the new technology (i.e. increased tower heights and rotor
diameters)
– BHE Renewables has initiated the process to establish an interconnection
agreement for a 50 MW battery storage facility at the Solar Star site, which can
be bid into the California energy storage market
BHE Renewables Appendix
BHE Renewables Overview
(1) Based on net owned capacity of 4,082 MW in operation and under construction as of January 31, 2017
(2) Forecast approximately 100 off-takers for the purchase of all the energy produced by the solar portfolio for a period up to 25 years
(3) Separate PPAs exist with Missouri Joint Municipal Electric Commission (20 MW), Kansas Power Pool (25 MW), City of Independence, Missouri (20 MW) and Kansas Municipal Energy Agency (7 MW)
(4) 83% of the Company's interests in the Imperial Valley Projects' Contract Capacity are currently sold to Southern California Edison Company under long-term power purchase agreements expiring in 2016
through 2026. Certain long-term power purchase agreement renewals for 244 MW have been entered into with other parties at fixed prices that expire from 2028-2039, of which 202 MW mature in 2039
BHE Solar
Geothermal
Natural Gas
BHE Wind
BHE Hydro
CalEnergy Philippines
Solar
36%
Wind
28%
Geothermal
8%
Hydro
4%
Natural Gas
24%
Portfolio Composition (1)
2017-2019
24%
2020-2029
7%
2030+
69%
Contract Maturities (1)
Location Installed
PPA
Expiration
Power
Purchaser
Net or
Contract
Capacity
(MW)
Net
Owned
Capacity
(MW)
SOLAR
Solar Star I & II CA 2013-2015 2035 SCE 586 586
Topaz CA 2013-2014 2040 PG&E 550 550
Agua Caliente AZ 2012-2013 2039 PG&E 290 142 Generation Mix
Alamo 6 TX 2017 2042 CPS 110 110
Community Solar
Gardens
MN 2016-2017 (2) (2) 95 95
1,631 1,483
WIND
Pinyon Pines I & II CA 2012 2035 SCE 300 300
Jumbo Road TX 2015 2033 Austin Energy 300 300
Bishop Hill II IL 2012 2032 Ameren 81 81
Grande Prairie NE 2016 2037 OPPD 400 400
Marshall Wind KS 2016 2036 (3) 72 72
1,153 1,153
GEOTHERMAL
Imperial Valley CA 1982-2000 (4) (4) 338 338
HYDROELECTRIC
Casecnan Phil. 2001 2021 NIA 150 128
Wailuku HI 1993 2023 Hawaii Electric 10 10
160 138
NATURAL GAS
Cordova IL 2001 2019 Exelon Generation 512 512
Power Resources TX 1988 2018 EDF Trading 212 212
Saranac NY 1994 2017
TransAlta
Energy Mktg
245 196
Yuma AZ 1994 2024 SDG&E 50 50
1,019 970
Total Owned and Under Construction 4,301 4,082
BHE Renewables – Net Income
($ millions) Years Ended Dec. 31
2016 2015 2014
Net Income:
Topaz 56 54 45
Solar Star 6 20 5
Agua Caliente 15 12 17
Bishop Hill 13 16 11
Pinyon Pines 13 1 12
Jumbo Road 10 4 1
Grande Prairie 8 1 -
Marshall 3 - -
MidAmerican Wind Tax Equity 37 4 -
BHE Geothermal (17) (18) 1
Wailuku Hydro 2 3 -
CalEnergy Philippines 47 42 39
Parent and Other (14) (15) (10)
BHE Renewables Combined Net Income 179 124 121
Current Tax Legislation –
Industry Impact
• 2015 Omnibus spending bill extended and phased out tax credits for wind and solar
• Wind PTC/ITC
• 2016 – 100%
• 2017 – 80%
• 2018 – 60%
• 2019 – 40%
– Retains “start of construction” language
– Developers will have the option to claim a 30% ITC instead of the PTC during the
same period and with the same phase down rate
• Solar ITC
• 2016-2019 – 30%
• 2020 – 26%
• 2021 – 22%
– Projects beginning construction in these years must be placed in-service by
December 31, 2023 to qualify. The ITC will revert to its permanent 10% level if
projects are not completed before January 1, 2024, or for projects that begin
construction after 2021
• 50% bonus depreciation extended for five years, now expiring January 1, 2020
– Ramps down to 40% and 30%, respectively, in the final two years
Mark Hewett
President and CEO
BHE Pipeline Group
2017 Fixed-Income Investor Conference
Shipper Contract Updates
2017-2018
28%
2019-2020
38%
2021-2022
8%
2023-2028
22%
2029+
4%
NNG – Market Area Transportation
Contract Maturities (1)
(2) Based on binding shipper commitments for recontracting and total
system design capacity of 2.2 million Dth per day
Kern River – Transportation
Contract Maturities (2)
(1) Based on maximum daily quantities of market area entitlement in
decatherms as of Dec. 31, 2016
• In 2016, completed approximately 1.2 Bcf/day in contract
renewals with a 2% increase in rates, which provides
additional $1.3 million in annual revenue
• Market Area Transportation weighted average remaining
contract term of five years
• 74% of 2016 storage revenue resulted from long-term
contracts, with an average remaining contract life of
approximately seven years
• Long-term contracts with creditworthy counterparties – top
10 customer groups have a weighted average credit rating
of BBB+/A3
• For Period One capacity expiring in 2016/2017, 94% elected to
extend their contracts at Period Two rates, with 220,923 Dth per
day electing 10-year contracts and 617,923 Dth per day electing
15-year contracts
• 55% of capacity is committed to contracts that expire after 2019
• Weighted average remaining contract term of eight years
• Weighted average shipper rating of BBB+/Baa1
• Shippers that do not meet credit standards are required to post
collateral
2017
5%
2018-2019
36%
2020-2021
5%
2025-2028
16%
2031
31%
2032-2033
3%
Uncontracted
4%
Kern River Gas Transmission
Rate Proposal
• On December 1, 2016, Kern River filed a proposal to establish an alternate set of Period Two
rates for its customers
– Uncontested settlement with all shippers either supporting or not opposing
– FERC approved January 27, 2017
– Additional Period Two option for 25-year term compared with current options of 10 or 15 years
– Applies to customers who are currently in Period Two, committed to Period Two or eligible for Period Two
in the future
– Customers may continue with existing Period Two rates or choose the Alternate Period Two rates
– Alternate Period Two rates are specific to each respective customer group
• Initial contract term of 10 or 15 years with the option to extend to 25 years
– Book depreciation rates adjusted to extend the depreciable life of transmission assets to 2056
– Outstanding debt to be redeemed April 13, 2017
• 100% equity capitalization is reflected in Period Two rates
• Benefits
– Increases the likelihood of customers re-contracting capacity expiring in 2018
• Alternate Period Two rates approximately $0.02 - $0.07 per Dth lower than current Period Two rates
• Alternate Period Two rates correlate better with the forward spread
– Provides a third option to customers considering Period Two service
– Extends rate base
$177
$149 $140 $153 $164 $149
$68
$70
$44
$137
$24
$145
-
50
100
150
200
250
300
350
2014 2015 2016 2017F 2018F 2019F
$
M
il
li
on
s
Northern Natural Gas Capital Expenditures
Operating Development
Capital Investment Plan
$16
$29
$42 $41
$28
$15
$2
$1
-
10
20
30
40
50
2014 2015 2016 2017F 2018F 2019F
$
M
il
li
on
s
Kern River Gas Capital Expenditures
Operating Development
($ millions)
2017-2019
Current
Plan
Prior
Plan
Operating $ 466 $ 351
Development 306 212
Total $ 772 $ 563
($ millions)
2017-2019
Current
Plan
Prior
Plan
Operating $ 84 $ 79
Development - -
Total $ 84 $ 79
Focus on Customer Satisfaction
– Northern Natural Gas ranked #1 and Kern River ranked #2 out of 36 interstate pipelines in Mastio & Company‟s
2017 survey; Northern Natural Gas also ranked #1 among mega-pipelines in customer satisfaction and Kern
River ranked #1 among regional pipelines in customer satisfaction
– BHE Pipeline Group has been ranked #1 for 12 consecutive years
Location
– Northern Natural Gas - Reticulated system - economically unfeasible to replicate
– Northern Natural Gas - Optionality with Field Area - tremendous advantage for customers and pipeline to
capture opportunities
– Kern River - Directly connected to end-use markets in Nevada and California
Competitive Pricing
– Both pipelines have demonstrated over 10 years of rate stability with no Section 4 regulatory rate review since
2004 by actively managing and growing our business and solving business issues
– Northern Natural Gas - Prices are competitive with other pipelines which minimizes level of discounting needed
in competitive markets
– Kern River - Period Two rates are the lowest delivered cost interstate pipeline options to southern California
– Long-term contracts with stable markets for both pipelines
Operational Excellence
– Northern Natural Gas - Long history of commitment to system reliability and operational excellence
– Kern River - State of the art transmission system
Financial Strength and Stability
– Northern Natural Gas - Interest coverage of 9.5x in 2016 reflects significant improvement in financial stability
since the company was acquired by BHE in 2002 when the metric was 3.1x
– Kern River - 100% equity capitalization consistent with tariff design
Competitive Advantages
BHE Pipeline Group Appendix
• 900 employees
• 14,700-mile interstate natural gas
transmission pipeline system
• Market Area design capacity of 5.8
Bcf/day plus 1.7 Bcf/day Field Area
delivery capacity to the Market Area
• Five natural gas storage facilities, with
a total firm capacity of more than 79 Bcf
and more than 2.0 Bcf of peak day
delivery capability
• Access to five major traditional supply
regions and direct access to two non-
traditional (tight sands and shale)
supply regions
• Annual average deliveries of 1,005 Bcf
over the prior three years – 1,031 Bcf in
2016
Northern Natural Gas
Overview
• 2016 Field Area Expansion
– Total capital expenditures of approximately $28 million, serving a customer in Permian Basin
– Incremental entitlement of 142,000 Dth/day
– Annual demand revenues of $10 million, with contract terms up to 12 years
• 2017-19 Market Area Expansions
– 2017 Projects – total capital expenditures of approximately $70 million, primarily serving LDCs
• Incremental entitlement of 87,937 Dth/day
• Annual demand revenues of $8 million, with contract terms from 4 to 10 years
– 2018-19 Projects – total capital expenditures of approximately $86 million, primarily serving LDCs
and a power plant
• Incremental entitlement of 89,892 Dth/day
• Pending regulatory approval with annual demand revenues of $15 million, with contract terms of 21 to 25
years
• Future Field Area Expansion
– Total capital expenditures of approximately $37 million, serving power plant expansion
– Incremental entitlement of 210,000 Dth/day
– 2017 in-service with annual demand revenues of $10 million, with contract term of 13 years
Northern Natural Gas
Expansion Projects
Kern River Gas Transmission
Overview
• Headquartered in Salt Lake City,
Utah
• 150 employees
• 1,700-mile interstate natural gas
transmission pipeline system
• Delivers natural gas from Rocky
Mountain basins to markets in
Utah, Nevada and California
• Design capacity: 2.2 million Dth
per day of natural gas
• Over 90% of capacity contracted
under long-term contracts
CALIFORNIA
UTAH
WYOMING
ARIZONA
NEVADA
Kern River Gas Transmission
Strong Demand for Services
Daily Average Scheduled Volume
2016 Deliveries by State
(1) Based on the 2016 California Gas Report
(2) Based on Kern River’s average scheduled volumes to Nevada and
Southwest Gas Transmission Company’s system capacity served by
El Paso Natural Gas Company, LLC or Transwestern Pipeline
Company, LLC.
• Received 29% of Rockies
natural gas supply in 2016
• Delivered approximately 20%(1)
of California‟s demand for
natural gas in 2015
• Delivered more than 82%(2) of
southern Nevada‟s natural gas
• During 2016, scheduled
throughput averaged 110% of
design capacity
0
500
1,000
1,500
2,000
2,500
3,000
2008 2009 2010 2011 2012 2013 2014 2015 2016
D
th
in
m
ill
io
n
s
Scheduled Design
California
69% Nevada
27%
Utah
4%
Lowest-Cost Option to Southern California
Scott Thon
President and CEO
AltaLink
2017 Fixed-Income Investor Conference
AltaLink Regulatory Update
2015-2016 General Tariff Application (GTA)
− The Alberta Utilities Commission (AUC) approved 98% of requested operating expenses
− Tariff relief of C$600 million (2015-2018) approved
2012-2013 Direct Assign Capital Deferral Account (DACDA)
− AUC approved C$1.862 billion of the total C$1.977 billion of capital projects
− C$109 million deferred to a future DACDA
− Minor disallowances, anticipate 100% recoverability from third parties
2016 Generic Cost of Capital Decision (GCOC)
− ROE was set at 8.3% for 2016 and 8.5% for 2017 (8.3% for 2013-2015)
− Equity thickness of 37% for 2016 and 2017 (36% for 2013-2015)
− AUC continues to support „A‟ category credit ratings
2017-2018 GTA
− Traditionally AUC did not allow GTA negotiated settlement
− In December 2016, the AUC approved the request to enter into a negotiated settlement
process with intervenors
− Successfully reached a negotiated settlement in principle on January 27, 2017
− Filing of the negotiated settlement took place on February 8, 2017, which includes
C$58 million of additional savings for customers and C$130.3 million related to a depreciation
surplus refund
− Intervenor requests & responses completed in March 2017
2015-2016 GTA
• The AUC approved C$600 million of customer rate relief in its decision
• Reduces business risk by mitigating customer rate concerns
• Rate relief coming at an optimal time given macroeconomic environment
• Stepping up for customers with win-win solutions
• Received significant support from customers, particularly industrials
C$600 million of Customer Rate Relief Approved
Approved Customer Rate Relief: 2015-2018 impact
* 2017 and 2018 exclude approximately C$157 million of incremental proposed rate relief related
to depreciation and salvage and an additional C$58 million related to a negotiated settlement
2015 2016 2017 2018
Discontinuation of CWIP-in-rate base 69 13 4 2
Refund of previously collected CWIP-in-rate base 123 142 - -
Change from future income tax to flow through - 68 89 90
Total rate relief 192 223 93 92
Cumulative relief 192 415 508 600
Reported Net income 209 306
Normalized Net income 237 290
Customer Rate Relief (C$ millions)
Rate Base Investment Largely Complete
CWIP balance negligible in 2016
(C$ billions)
Forecast based on 2017-18 GTA, February 2017
2.5
3.5
5.3
7.0
1.2
1.8
1.3
0.2
3.7
5.3
6.6
7.2
$0.0
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
$8.0
2013A 2014A 2015A 2016A
Mid-year Rate Base Mid-year CWIP
AltaLink Capital Expenditures Normalizing
0.1 0.2 0.2 0.2
0.3 0.2
1.7
1.9
0.9
0.6 0.3
0.1
$0.0
$0.5
$1.0
$1.5
$2.0
2013A 2014A 2015A 2016A 2017F 2018F
Operating Development
73,000
74,000
75,000
76,000
77,000
78,000
79,000
80,000
81,000
2012A 2013A 2014A 2015A 2016A
4.5
5.0
5.5
6.0
6.5
7.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
11.0
N
o
v
-1
3
J
a
n
-1
4
Ma
r-
1
4
Ma
y
-1
4
J
u
l-
1
4
S
e
p
-1
4
N
o
v
-1
4
J
a
n
-1
5
Ma
r-
1
5
Ma
y
-1
5
J
u
l-
1
5
S
e
p
-1
5
N
o
v
-1
5
J
a
n
-1
6
Ma
r-
1
6
Ma
y
-1
6
J
u
l-
1
6
S
e
p
-1
6
N
o
v
-1
6
(C$ billions)
International exports (left)
Manufacturing shipments (right)
Alberta Economy Slows but Stabilizing late in 2016
Alberta
• In 2016, Alberta was Canada‟s third largest economy and fourth most populated
province
• After falling for most of the first half of 2016, activity in the province began to
improve in the latter half of the year
• In December 2016, Alberta‟s unemployment rate was 8.1% versus the Canadian
average of 7.0%. Alberta‟s labor market is improving with job gains in four of the
last five months
• The value of Alberta‟s exports have increased alongside oil production growth and
higher oil prices
AltaLink
• Economy has caused delays in oil and gas grid connections; those delays are
offset by renewable energy connection requests
• After strong growth, load is leveling
• AltaLink is not exposed to volume or price risk
• AltaLink is focused on addressing customer cost concerns
Source: Alberta Electric System Operator
Source: Statistics Canada
Business output rebounds from recession lows
Alberta Electricity Demand (GWh)
+0.4%
+3.2%
+2.5%
-0.9%
64.3
80.2
49.4
33.3
18.3
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
2012A 2013A 2014A 2015A 2016A
Average Pool Prices ($/MWh)
(C$ billions)
Alberta’s Climate Leadership Plan
• Alberta government introduced its Climate Leadership Plan (CLP) in November 2015
• Coal generation fully transitioning out of Alberta by 2030
− By 2030, one-third of Alberta‟s coal generating capacity is expected to be replaced by
renewable energy; two-thirds will be replaced by natural gas
− An economy-wide carbon tax was implemented January 1, 2017, to encourage energy
efficiency and cover the cost of transitioning to renewables
• A RFP for new renewable energy capacity is expected in Q2/Q3 2017
• First 400 MW of renewables to be in-service by 2019
• AltaLink transmission system ready to enable CLP
Gas
70%
Hydroelectric
4%
Wind
24%
Other
2%
2030 Alberta Generation Mix
Coal
39%
Gas
45%
Hydroelectric
5%
Wind
9%
Other
2%
2016 Alberta Generation Mix
AltaLink Appendix
AltaLink, L.P.
• AltaLink is an owner and operator of
regulated electricity transmission
facilities in the Province of Alberta
– Supplies electricity to approximately 85%
of Alberta‟s population
• AltaLink owns approximately 8,150 miles
of transmission lines and 309
substations within the Province of
Alberta
– No volume or commodity exposure
– Supportive regulatory environment
– Revenue from AA- rated Alberta Electric
System Operator (AESO)
• Mid-year 2016 rate base and CWIP was
C$7.2 billion
• AltaLink receives approved tariff from
AESO in equal monthly installments
– No exposure to variability in electricity
prices
– No electricity volume risk
• Tariffs based on cost-of-service
regulatory model under a forward test
year basis
• The AESO, who is responsible for
system planning, directs substantially all
of AltaLink‟s capital spending
Users
(Distribution Companies, Direct Connects, Generators)
Regulator
Approves regulated
transmission tariff
TFO provides
transmission
service
AESO provides open
transmission access
Users pay
transmission tariff to
AESO
AESO pays approved revenue
requirement
Regulatory Framework Supports
Predictable Revenue
Phil Jones
President and CEO
Northern Powergrid Holdings Company
2017 Fixed-Income Investor Conference
Regulatory Price Control Overview
• Our performance in ED1 continues to improve
– Solid start to the first two years of the ED1
period, with costs and outputs on target
– Fastest improvements achieved in overall
customer satisfaction during the year
– Best ever year on network performance helped
by automated switching and intelligent fuses
– Lower debt rates are a value-creation
opportunity; £450 million issued in the first two
years of ED1 at a blended average rate of 2.49%
• The regime continues to be stable and the
RIIO model is widely viewed as a success
– Revenues reduce and RAV grows as regulatory
asset life transitions to 45 years
– Efficient delivery of network outputs is crucial
– Incentives remain central on cost efficiency and
output delivery
– Inflation protection continues to apply
– Strong credit ratings compare well with the rest
of the sector
1 – Plus RPI inflation
2 – ED1 indexed, figure stated for 2016-2017
3 – Total activity costs
4 – 2012-2013 prices
(£ millions) - US GAAP 2016 2015
Revenues 735 746
Operating income
314 389
Capex
404 470
RAV
2,993 2,844
Interest cover 3.5x 4.1x
Debt to RAV 62% 62%
Regulatory parameters ED1 DPCR5
Allowed equity returns
1
6.0% 6.7%
Allowed cost of debt
1,2
2.4% 3.6%
Annual totex
3
vs DPCR5 95% 100%
Average annual RAV
4
growth
1.2% 3.7%
Regulatory asset life 20-45
years
20
years
Capital Investment Plan
• Operating capital delivers our ED1 output commitments
• The smart meter rental business has grown significantly from the prior plan with total
plan capex increasing by £183 million, CAGR from 2014 to 2017 is 63%
£377 £388
£329 £348 £331 £325
£35
£53
£98
£125
£86
£11
-
100
200
300
400
500
2014 2015 2016 2017F 2018F 2019F
£
M
il
li
on
s
Operating Development
(£ millions)
2017-2019
Current
Plan
Prior
Plan
Operating £ 1,004 £ 1,025
Development 222 5
Total £ 1,226 £ 1,030
U.K. and European Economic Outlook
Source: IMF, World Economic Outlook
• Our assessment of Brexit is unchanged – the
fundamentals of our business are not directly
affected
– Sustainability objectives are largely independent of EU
– UK regulatory framework is at the leading edge of EU
– Strategic interests in energy co-operation seem to
promote the status quo
• Currency fall has affected our contribution to BHE
• The low inflation we faced a year ago has ended
– Some foreign sourced input prices have increased
– Offset by price control inflation protection
• Driving growth across the country has moved up
the domestic policy agenda
– The productivity gap between London and the regions
is a growing concern
– Brexit is driving a move to more targeted, government-
led industrial strategy
1
1.2
1.4
1.6
1.8
2
2.2
Ex
ch
an
ge
r
at
e
($
/£
)
Spot rate Average, 10 years to present
95
100
105
110
115
120
125
GD
P
(2
00
5 =
1
00
)
UK Euro area USA
UK Euro area USAJan 2017:
Jan 2016:
Source: IMF, World Economic Outlook
Minimal impact on UK growth so far…
… but felt acutely on exchange rate
• Our existing network continues to provide development opportunities
– Our ED1 business plan includes £83 million to enhance communications and controls
– Distribution network operators are expected to transition to flexible distribution system
operators to cope with increased diversity in supply and demand
• Smart meters are providing organic growth, whereas in the oil and gas sector low
commodity prices have diminished opportunities
– Our smart meter rental business continues to deliver results, growth in 2016 exceeded
projections. We now have over three million new smart meters contracted for a total
investment of £480 million
– Low oil and gas prices have restricted CE Resources‟ exploration and development activity
• Equity funds have dominated recent deals, driving up prices
– National Grid sold 61% of their gas distribution business to a Macquarie-led consortium
valuing the business at £13.8 billion (US$17.4 billion) at 1.59 times RAV
– Infracapital sold Calvin Capital to KKR so curtailing the auction process early
– 50.4% stake in a 99% lease of Ausgrid sold to an Australian consortium at A$16.2 billion (a
RAV premium of 41%) after higher Chinese bids were rejected on security grounds
Growth Opportunities in the U.K.
Northern Powergrid Appendix
Northern Powergrid
Leeds
Edinburgh
Middlesbrough
Newcastle Upon Tyne
Sheffield
York
Northeast
Yorkshire
• 3.9 million end-users in northern England
• Approximately 60,000 miles of distribution lines
• Approximately 67% of 2016 distribution revenue
from residential and commercial customers
through December 31, 2016
• Distribution revenue (£ millions):
• Strong start to the ED1 period (eight-year price
control started April 2015) with total expenditure
for the 2015/2016 regulatory year at 97.1% of
allowances and outputs 14.3% ahead of target.
Groundwork now laid for delivering commitments
effectively over the eight-year period
• In 2016, a step-change is being achieved in
overall customer satisfaction, from an average
ranking of 5th in 2015 to an average ranking of
3rd in 2016
Twelve Months Ended
12/31/16 12/31/15
Residential 334 345
Commercial 109 117
Industrial 209 203
Other 9 9
Total 661 674
Greg Abel
Chairman, President and CEO
Berkshire Hathaway Energy
2017 Fixed-Income Investor Conference
Berkshire Hathaway Energy
Vision
To be the best energy company in serving our customers, while delivering sustainable energy solutions
Culture
Personal responsibility to our customers
Strategy
Reinvest in our businesses
• Continue to invest in our employees and
operations, maintenance and capital
programs for property, plant and equipment
• Position our regulated assets to manage
bypass risk by providing excellent service
and competitive rates to our customers
• Decarbonize our operations by participating
in energy policy development, transforming
our businesses and assets
• Advance cybersecurity and physical security
programs
Invest in internal growth
• Pursue the development of a value-enhancing
energy grid and gas pipeline infrastructure
• Create customer solutions through innovative
rate design and redesign
• Grow our portfolio of renewable energy
• Develop strong cybersecurity and physical
resilience programs
Acquire companies
• Additive to business model
Competitive Advantage
Berkshire Hathaway Ownership
Questions
